10-Q 1 cpk331201410-q.htm 10-Q CPK 3.31.2014 10-Q
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
 
 
FORM 10-Q
 
 
 
 

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: March 31, 2014
OR
¨
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                       to                      
Commission File Number: 001-11590 
 
 
 
CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)
 
 
 

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
Common Stock, par value $0.48679,701,040 shares outstanding as of April 30, 2014.



Table of Contents
 




GLOSSARY OF DEFINITIONS

401(k) SERP: Supplemental Executive Retirement Savings Plan
ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Austin Cox: Austin Cox Home Services, Inc.
BravePoint: BravePoint®, Inc., our advanced information services subsidiary, headquartered in Norcross, Georgia
Calpine: Calpine Energy Services, L.P.
CDD: Cooling degree-days, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit
Chesapeake: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake
Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and Necessity
Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers and fees
Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia
DNREC: Delaware Department of Natural Resources and Environmental Control
DSCP: Directors Stock Compensation Plan
Dts/d: Dekatherms per day
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake
EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of Eastern Shore Gas Company
EPA: United States Environmental Protection Agency
ESG: Eastern Shore Gas Company and its affiliates
FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission, an independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil
FDEP: Florida Department of Environmental Protection
FDOT: Florida Department of Transportation
FGT: Florida Gas Transmission Company
Fort Meade: The natural gas system purchased by FPU from the City of Fort Meade, Florida
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
Glades: Glades Gas Co., Inc.
GRIP: Gas Reliability Infrastructure Program, which is a surcharge to natural gas customers designed to recover capital and other program-related costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services in Florida
Gulf Power: Gulf Power Company
Gulfstream: Gulfstream Natural Gas System, LLC
HDD: Heating degree-days, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit
MDE: Maryland Department of Environment
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
NAM: Natural Attenuation Monitoring
Note Agreement: Note Purchase Agreement entered into by Chesapeake with Note Holders on September 5, 2013
Note Holders: PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company, which are collectively the lenders that entered into the Note Agreement with Chesapeake on September 5, 2013
Notes: Series A and B unsecured Senior Notes that have been or will be entered into with the Note Holders
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., our wholly-owned Florida intrastate pipeline subsidiary
PESCO: Peninsula Energy Services Company, Inc., our wholly-owned natural gas marketing subsidiary
PIP: Performance Incentive Plan
PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida
Sandpiper: Sandpiper Energy, Inc.
Sanford Group: FPU and other responsible parties involved with the Sanford environmental site
SEC: Securities and Exchange Commission
Series A Notes: Series A of the unsecured Senior Notes issued on December 16, 2013 pursuant to the Note Agreement
Series B Notes: Series B of the unsecured Senior Notes to be issued on May 15, 2014 pursuant to the Note Agreement
Sharp: Sharp Energy, Inc., our wholly-owned propane distribution subsidiary
SICP: 2013 Stock and Incentive Compensation Plan, which replaced DSCP and PIP effective May 2, 2013
TETLP: Texas Eastern Transmission, LP
Xeron: Xeron, Inc., our propane wholesale marketing subsidiary, based in Houston, Texas




PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands, except shares and per share data)
 
 
 
 
Operating Revenues
 
 
 
 
Regulated energy
 
$
102,166

 
$
81,566

Unregulated energy
 
79,973

 
54,991

Other
 
4,198

 
4,172

Total Operating Revenues
 
186,337

 
140,729

Operating Expenses
 
 
 
 
Regulated energy cost of sales
 
54,307

 
41,615

Unregulated energy and other cost of sales
 
61,325

 
40,090

Operations
 
26,626

 
21,754

Maintenance
 
2,148

 
1,722

Depreciation and amortization
 
6,635

 
5,820

Other taxes
 
3,673

 
3,178

Total Operating Expenses
 
154,714

 
114,179

Operating Income
 
31,623

 
26,550

Other income, net of other expenses
 
6

 
289

Interest charges
 
2,155

 
2,072

Income Before Income Taxes
 
29,474

 
24,767

Income taxes
 
11,793

 
9,898

Net Income
 
$
17,681

 
$
14,869

Weighted Average Common Shares Outstanding:
 
 
 
 
Basic
 
9,658,431

 
9,601,529

Diluted
 
9,693,434

 
9,678,950

Earnings Per Share of Common Stock:
 
 
 
 
Basic
 
$
1.83

 
$
1.55

Diluted
 
$
1.82

 
$
1.54

Cash Dividends Declared Per Share of Common Stock
 
$
0.385

 
$
0.365

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,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Net Income
 
$
17,681

 
$
14,869

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
Amortization of prior service cost, net of tax of ($6) and ($6), respectively
 
(9
)
 
(9
)
Net gain, net of tax of $27 and $38, respectively
 
40

 
58

Total other comprehensive income
 
31

 
49

Comprehensive Income
 
$
17,712

 
$
14,918

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,
2014
 
December 31,
2013
(in thousands, except shares)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated energy
 
$
697,725

 
$
691,522

Unregulated energy
 
76,938

 
76,267

Other
 
21,129

 
21,002

Total property, plant and equipment
 
795,792

 
788,791

Less: Accumulated depreciation and amortization
 
(179,918
)
 
(174,148
)
Plus: Construction work in progress
 
27,228

 
16,603

Net property, plant and equipment
 
643,102

 
631,246

Current Assets
 
 
 
 
Cash and cash equivalents
 
4,791

 
3,356

Accounts receivable (less allowance for uncollectible accounts of $1,976 and $1,635, respectively)
 
80,313

 
75,293

Accrued revenue
 
12,536

 
13,910

Propane inventory, at average cost
 
6,088

 
10,456

Other inventory, at average cost
 
3,728

 
4,880

Storage gas prepayments
 
1,323

 
4,318

Prepaid expenses
 
4,890

 
6,910

Income taxes receivable
 

 
2,609

Mark-to-market energy assets
 

 
385

Regulatory assets
 
4,342

 
2,436

Deferred income taxes
 
1,723

 
1,696

Other current assets
 
198

 
160

Total current assets
 
119,932

 
126,409

Deferred Charges and Other Assets
 
 
 
 
Investments, at fair value
 
2,951

 
3,098

Regulatory assets
 
66,395

 
66,584

Goodwill
 
4,625

 
4,354

Other intangible assets, net
 
2,875

 
2,975

Receivables and other deferred charges
 
2,681

 
2,856

Total deferred charges and other assets
 
79,527

 
79,867

Total Assets
 
$
842,561

 
$
837,522

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

- 3


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities
 
March 31,
2014
 
December 31,
2013
(in thousands, except shares and per share data)
 
 
 
 
Capitalization
 
 
 
 
Stockholders’ equity
 
 
 
 
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)
 
$
4,715

 
$
4,691

Additional paid-in capital
 
152,862

 
152,341

Retained earnings
 
138,176

 
124,274

Accumulated other comprehensive loss
 
(2,502
)
 
(2,533
)
Deferred compensation obligation
 
1,138

 
1,124

Treasury stock
 
(1,138
)
 
(1,124
)
Total stockholders’ equity
 
293,251

 
278,773

Long-term debt, net of current maturities
 
117,195

 
117,592

Total capitalization
 
410,446

 
396,365

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
10,955

 
11,353

Short-term borrowing
 
83,470

 
105,666

Accounts payable
 
58,183

 
53,482

Accrued compensation
 
4,937

 
8,394

Accrued interest
 
2,536

 
1,235

Dividends payable
 
3,730

 
3,710

Income taxes payable
 
8,955

 

Mark-to-market energy liabilities
 

 
127

Regulatory liabilities
 
7,071

 
4,157

Customer deposits and refunds
 
24,405

 
26,140

Other accrued liabilities
 
8,934

 
7,678

Total current liabilities
 
213,176

 
221,942

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
142,414

 
142,597

Deferred investment tax credits
 
65

 
74

Regulatory liabilities
 
4,178

 
4,402

Accrued asset removal cost—Regulatory liability
 
40,007

 
39,510

Environmental liabilities
 
9,129

 
9,155

Other pension and benefit costs
 
20,662

 
21,000

Other liabilities
 
2,484

 
2,477

Total deferred credits and other liabilities
 
218,939

 
219,215

Other commitments and contingencies (Note 6)
 

 

Total Capitalization and Liabilities
 
$
842,561

 
$
837,522

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


- 4


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

 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net income
 
$
17,681

 
$
14,869

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
6,635

 
5,820

Depreciation and accretion included in other costs
 
1,783

 
1,476

Deferred income taxes, net
 
(231
)
 
2,208

Gain on sale of assets
 
(8
)
 
(8
)
Unrealized (gain) loss on commodity contracts
 
68

 
(214
)
Unrealized gain on investments
 
(37
)
 
(283
)
Realized gain on sales of investments, net
 

 
(69
)
Employee benefits
 
162

 
209

Share-based compensation
 
638

 
381

Other, net
 
(1
)
 
(3
)
Changes in assets and liabilities:
 
 
 
 
Sale (purchase) of investments
 
184

 
(7
)
Accounts receivable and accrued revenue
 
(3,647
)
 
(8,657
)
Propane inventory, storage gas and other inventory
 
8,243

 
5,064

Regulatory assets
 
(2,788
)
 
852

Prepaid expenses and other current assets
 
2,185

 
1,469

Accounts payable and other accrued liabilities
 
4,821

 
1,510

Income taxes receivable and payable
 
11,565

 
8,899

Accrued interest
 
1,301

 
1,185

Customer deposits and refunds
 
(1,735
)
 
(2,520
)
Accrued compensation
 
(3,505
)
 
(2,753
)
Regulatory liabilities
 
2,925

 
5,711

Other assets and liabilities, net
 
(240
)
 
21

Net cash provided by operating activities
 
45,999

 
35,160

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(18,464
)
 
(16,409
)
Proceeds from sales of assets
 
29

 
34

Acquisitions
 

 
(2,437
)
Environmental expenditures
 
(26
)
 
(20
)
Net cash used in investing activities
 
(18,461
)
 
(18,832
)
Financing Activities
 
 
 
 
Common stock dividends
 
(3,369
)
 
(3,176
)
Purchase of stock for Dividend Reinvestment Plan
 
(341
)
 
(326
)
Change in cash overdrafts due to outstanding checks
 
(501
)
 
83

Net repayment under line of credit agreements
 
(21,696
)
 
(13,647
)
Repayment of long-term debt and capital lease obligation
 
(196
)
 
(15
)
Net cash used in financing activities
 
(26,103
)
 
(17,081
)
Net Increase (Decrease) in Cash and Cash Equivalents
 
1,435

 
(753
)
Cash and Cash Equivalents—Beginning of Period
 
3,356

 
3,361

Cash and Cash Equivalents—End of Period
 
$
4,791

 
$
2,608

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

- 5


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
 
 
Common Stock
 
 
 
 
 
 
 
 
 
 
 
 
(in thousands, except shares and per share data)
Number  of
Shares(1)
 
Par
Value
 
Additional  Paid-In
Capital
 
Retained
Earnings
 
Accumulated  Other Comprehensive
Loss
 
Deferred
Compensation
 
Treasury
Stock
 
Total
Balance at December 31, 2012
9,597,499

 
$
4,671

 
$
150,750

 
$
106,239

 
$
(5,062
)
 
$
982

 
$
(982
)
 
$
256,598

Net Income

 

 

 
32,787

 

 

 

 
32,787

Other comprehensive income

 

 

 

 
2,529

 

 

 
2,529

Dividend declared ($1.520 per share)

 

 
(6
)
 
(14,752
)
 

 

 

 
(14,758
)
Conversion of debentures
17,383

 
8

 
287

 

 

 

 

 
295

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

 
12

 
1,310

 

 

 

 

 
1,322

Treasury stock activities

 

 

 

 

 
142

 
(142
)
 

Balance at December 31, 2013
9,638,230

 
4,691

 
152,341

 
124,274

 
(2,533
)
 
1,124

 
(1,124
)
 
278,773

Net Income

 

 

 
17,681

 

 

 

 
17,681

Other comprehensive income

 

 

 

 
31

 

 

 
31

Dividend declared ($0.385 per share)

 

 
(1
)
 
(3,779
)
 

 

 

 
(3,780
)
Conversion of debentures
31,542

 
15

 
520

 

 

 

 

 
535

Share-based compensation and tax benefit (2) (3)
17,906

 
9

 
2

 

 

 

 

 
11

Treasury stock activities

 

 

 

 

 
14

 
(14
)
 

Balance at March 31, 2014
9,687,678

 
$
4,715

 
$
152,862

 
$
138,176

 
$
(2,502
)
 
$
1,138

 
$
(1,138
)
 
$
293,251

 
(1) 
Includes 34,731 and 34,495 shares at March 31, 2014 and December 31, 2013, 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 quarter ended March 31, 2014 and for the year ended December 31, 2013, we withheld 8,458 and 10,411 shares, respectively, for taxes.

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


- 6


NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
1.
Summary of Accounting Policies
Basis of Presentation
References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.
The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.
Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.
We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.
Reclassifications
We reclassified certain amounts in the condensed consolidated cash flows statement for the three months ended March 31, 2013 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
Income Taxes (ASC 740) - In July 2013, the FASB issued ASU 2013-11, Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists, which requires the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of an uncertain tax position. ASU 2013-11 became effective for us on January 1, 2014. The adoption of ASU 2013-11 had no material impact on our financial position and results of operations.



- 7


2.
Calculation of Earnings Per Share

 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands, except shares and per share data)
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
Net Income
 
$
17,681

 
$
14,869

Weighted average shares outstanding
 
9,658,431

 
9,601,529

Basic Earnings Per Share
 
$
1.83

 
$
1.55

Calculation of Diluted Earnings Per Share:
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
Net Income
 
$
17,681

 
$
14,869

Effect of 8.25% Convertible debentures (1)
 

 
11

Adjusted numerator—Diluted
 
$
17,681

 
$
14,880

Reconciliation of Denominator:
 
 
 
 
Weighted shares outstanding—Basic
 
9,658,431

 
9,601,529

Effect of dilutive securities:
 
 
 
 
Share-based Compensation
 
35,003

 
23,132

8.25% Convertible debentures (1)
 

 
54,289

Adjusted denominator—Diluted
 
9,693,434

 
9,678,950

Diluted Earnings Per Share
 
$
1.82

 
$
1.54

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

- 8


3.
Acquisitions
Eastern Shore Gas Company
On May 31, 2013, the Maryland PSC approved the acquisition of ESG. Upon receiving this approval, we completed the purchase of the operating assets of ESG, which was not related to, or affiliated with, our interstate natural gas transmission subsidiary, Eastern Shore. We paid approximately $16.5 million at the closing of the transaction, which was subject to certain adjustments specified in the asset purchase agreement. During the third quarter of 2013, the purchase price was reduced by $543,000 due to adjustments to property, plant and equipment, propane inventory, accounts receivable and other accrued liabilities. The purchase price included approximately $726,000 of sales tax related to the transaction. We financed the acquisition using unsecured short-term debt.
Approximately 11,000 residential and commercial underground propane distribution system customers and 500 bulk propane delivery customers acquired in the transaction are being served by our new subsidiary, Sandpiper, and our propane distribution subsidiary, Sharp, respectively. Sandpiper's operations, which cover all of Worcester County, Maryland, are now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution. Although these customers are currently being served with propane, we classify Sandpiper's operations as natural gas distribution in the Regulated Energy segment.
In connection with this acquisition, we recorded $12.6 million in property, plant and equipment, $344,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of the purchase price adjustment in the third quarter of 2013. All but insignificant amounts of assets and liabilities are recorded in the Regulated Energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are preliminary, and we will complete the final purchase price allocation as soon as practicable, but no later than one year from the purchase of the assets.
The revenue and net income from this acquisition for the three months ended March 31, 2014 included in our condensed consolidated statement of income were $10.3 million and $1.7 million, respectively.
Other Acquisitions
On December 2, 2013, we acquired certain operating assets of the City of Fort Meade, Florida, for approximately $792,000. The purchased assets are used to provide natural gas distribution service in the City of Fort Meade, Florida. In connection with this acquisition, we recorded $670,000 in property, plant and equipment, $14,000 in inventory, $150,000 in goodwill and $42,000 in other current liabilities. Valuation of certain property, plant and equipment is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.
On February 5, 2013, we purchased the propane operating assets of Glades for approximately $2.9 million. The purchased assets are used to provide propane distribution service to approximately 3,000 residential and commercial customers in Okeechobee, Glades and Hendry Counties, Florida. In connection with this acquisition, we recorded $1.6 million in property, plant and equipment, $231,000 in propane and other inventory, $300,000 in an intangible asset related to Glades’ customer list, to be amortized over 12 years beginning in February 2013 and $724,000 in goodwill. All of the goodwill is expected to be deductible for income tax purposes. These amounts reflected an adjustment to the allocation of the purchase price during the first quarter of 2014 based on our final valuation, which decreased the value of propane inventory by $271,000 and increased goodwill for the same amount. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.

4.
Rates and Other Regulatory Activities
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.
Delaware
There were no rates and other regulatory activities in Delaware during the first quarter of 2014.

- 9


Maryland
On March 24, 2014, Sandpiper filed a depreciation study with the Maryland PSC regarding the assets purchased in the ESG acquisition. This depreciation study was filed in accordance with the order dated May 29, 2013, which allowed Sandpiper to recommend the proper depreciation rates and accumulated depreciation associated with the acquired assets. Sandpiper recommended slightly lower depreciation rates to be applied prospectively and a reduction of $4.5 million in accumulated depreciation. At the administrative meeting on April 23, 2014, the Maryland PSC assigned this matter to an administrative judge for further review.

Florida
On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU is seeking interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. We expect the interim rate relief to be determined in the second quarter of 2014. Any increase to our rates as a result of this interim rate relief will be subject to refund based on the outcome of the final rate relief, which we expect to occur during the fourth quarter of 2014.
On January 13, 2014, FPU's natural gas divisions and Chesapeake's Florida natural gas distribution division filed a consolidated natural gas depreciation study with the Florida PSC. We also filed for approval to establish a regulatory asset and related amortization to address the costs associated with the development of this study. Depending on the results of this proceeding, we may be required to change depreciation expense on our Florida natural gas distribution operations. The PSC agenda date for the depreciation study has not yet been set.
On November 15, 2013, Chesapeake's Florida natural gas distribution division petitioned the Florida PSC for an extension to its surcharge to recover an additional $381,000 in estimated remaining environmental cleanup costs that have not yet been recovered. This extension would be effective for two years beginning January 1, 2014. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda conference on January 7, 2014.

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

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

White Oak Lateral Project Filing: On June 13, 2013, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct the White Oak lateral project located in Kent County, Delaware. The project consists of installing approximately 5.5 miles of 16-inch diameter pipeline, metering facilities and miscellaneous appurtenances extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide 55,200 Dts/d of delivery lateral firm transportation service to an industrial customer facility currently under construction. The total cost of the project is estimated to be approximately $11.2 million.

On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013, with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013, and FERC staff recommended a finding of no significant impact. Eastern Shore filed the implementation plan and acceptance of conditions, stating that it will comply with all environmental conditions as set forth in the order. On November 27, 2013, the FERC issued a CP for this project. On January 17, 2014, the FERC issued its notice to allow construction to proceed, and Eastern Shore began construction activities for this project on January 22, 2014, for a planned in-service date of January 1, 2015.






- 10


5.
Environmental Commitments and Contingencies
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate at current and former operating sites the effect on the environment of the disposal or release of specified substances.
We have participated in the investigation and assessment of, and have remediation exposures at six former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding a seventh former MGP site located in Cambridge, Maryland.
As of March 31, 2014, we had approximately $10.2 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates, approximately $9.3 million of which has been recovered as of March 31, 2014. We had approximately $4.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $474,000 in environmental liabilities at March 31, 2014, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2014, we had approximately $598,000 in regulatory and other assets for future recovery through Chesapeake’s rates. Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants.
We continue to expect that all costs related to environmental remediation and related activities will be recoverable from customers through rates.
The following discussion provides details on MGP sites:
West Palm Beach, Florida
Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at, and in the immediate vicinity of, a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is currently implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. It is anticipated that similar remedial actions ultimately will be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 2014, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
The total cost of the final remedy is now estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of March 31, 2014, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million as provided in the Third Participation Agreement to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess

- 11


of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2014.
Key West, Florida
FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two new monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded via e-mail on October 9, 2012 that based on the data, NAM appears to be an appropriate remedy for the site. The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated that total costs to complete the remedial action will not exceed $50,000.
Pensacola, Florida
FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.
Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013.
An exploratory drilling program was conducted in November of 2013, and the most recent groundwater monitoring report was submitted on January 27, 2014. The results of the drilling program suggest that some additional remedial activities might be necessary in the southwest corner of the Winter Haven site, and, we are currently negotiating with FDEP the scope of such activities.
If modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs for the subsurface soils and groundwater at the site could be as much as $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, we continue to believe that the entire amount will be recoverable from customers through 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, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures previously discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

- 12


Salisbury, Maryland
We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.
Other
We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.
In a letter dated December 5, 2013, the DNREC notified us that it will be conducting a facility evaluation of a former MGP site in Seaford, Delaware. The facility evaluation has not been conducted and the outcome of this evaluation cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

6.
Other Commitments and Contingencies
Natural Gas, Electric and Propane Supply
Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2015.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's initial annual commitment is estimated at approximately 7.4 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.
In May 2013, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2014. 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 either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU having to provide an irrevocable letter of credit. As of March 31, 2014, FPU was in compliance with all of the requirements of its fuel supply contracts.
Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six -year term. Sharp's initial annual commitment is estimated at approximately 7.4 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one against those specified in the other.



- 13


Corporate Guarantees
The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45.0 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2014 was $31.6 million, with the guarantees expiring on various dates through February 2015.
Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, to the condensed consolidated financial statements for further details).
In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2014, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on December 2, 2014, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of March 31, 2014. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.
We provided a letter of credit for $2.3 million to TETLP related to the precedent agreement and firm transportation service agreement between our Delaware and Maryland divisions.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other regulatory authorities regarding income taxes and taxes other than income. As of March 31, 2014, we maintained a liability of $300,000 related to unrecognized income tax benefits and $968,000 related to contingencies for taxes other than income. As of December 31, 2013, we maintained a liability of $300,000 related to unrecognized income tax benefits and $1.0 million related to contingencies for taxes other than income.
Other
We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

7.
Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise three operating segments:
Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission operations and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.
Other. The “Other” segment consists primarily of our advanced information services subsidiary, as well as our unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

- 14


The following table presents financial information about our reportable segments:
 
 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
Regulated Energy
 
$
101,874

 
$
81,304

Unregulated Energy
 
79,874

 
54,991

Other
 
4,589

 
4,434

Total operating revenues, unaffiliated customers
 
$
186,337

 
$
140,729

Intersegment Revenues (1)
 
 
 
 
Regulated Energy
 
$
292

 
$
263

Unregulated Energy
 
99

 

Other
 
253

 
243

Total intersegment revenues
 
$
644

 
$
506

Operating Income
 
 
 
 
Regulated Energy
 
$
21,091

 
$
17,306

Unregulated Energy
 
10,858

 
9,369

Other and eliminations
 
(326
)
 
(125
)
Total operating income
 
31,623

 
26,550

Other income, net of other expenses
 
6

 
289

Interest
 
2,155

 
2,072

Income before Income Taxes
 
29,474

 
24,767

Income taxes
 
11,793

 
9,898

Net Income
 
$
17,681

 
$
14,869

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands)
 
March 31, 2014
 
December 31, 2013
Identifiable Assets
 
 
 
 
Regulated energy
 
$
715,062

 
$
708,950

Unregulated energy
 
103,658

 
100,585

Other
 
23,841

 
27,987

Total identifiable assets
 
$
842,561

 
$
837,522


Our operations are almost entirely domestic. BravePoint has infrequent transactions in foreign countries which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.
 

- 15


8.
Accumulated Other Comprehensive Income (Loss)
The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.
 
 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Beginning balance
 
$
(2,533
)
 
$
(5,062
)
Other comprehensive loss before reclassifications
 

 
(6
)
Amounts reclassified from accumulated other comprehensive loss
 
31

 
55

Net current-period other comprehensive income
 
31

 
49

Ending balance
 
$
(2,502
)
 
$
(5,013
)
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013:
 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
Prior service cost (1)
 
$
14

 
$
14

Net loss (1)
 
(66
)
 
(106
)
Total before income taxes
 
(52
)

(92
)
Income tax benefit
 
21

 
37

Net of tax
 
$
(31
)
 
$
(55
)
 
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
Amortization of defined benefit pension and postretirement plan items are included in operations expense in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.
 


- 16


9.
Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2014 and 2013 are set forth in the following tables:
 
 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Three Months Ended March 31,
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
 
2014
 
2013
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
107

 
$
102

 
$
647

 
$
594

 
$
23

 
$
21

 
$
13

 
$
12

 
$
17

 
$
16

Expected return on plan assets
 
(133
)
 
(126
)
 
(773
)
 
(719
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 
5

 
5

 
(19
)
 
(19
)
 

 

Amortization of net loss
 
37

 
57

 

 
81

 
12

 
16

 
17

 
18

 

 

Net periodic cost (benefit)
 
11

 
33

 
(126
)
 
(44
)
 
40

 
42

 
11

 
11

 
17

 
16

Amortization of pre-merger regulatory asset
 

 

 
190

 
190

 

 

 

 

 
2

 
2

Total periodic cost
 
$
11

 
$
33

 
$
64

 
$
146

 
$
40

 
$
42

 
$
11

 
$
11


$
19

 
$
18



We expect to record pension and postretirement benefit costs of approximately $578,000 for 2014. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $4.2 million and $4.4 million at March 31, 2014 and December 31, 2013, respectively. The amortization included in pension expense is being offset by a net periodic benefit of $191,000, which will reduce our total expected benefit costs to $578,000.
FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the merger pursuant to a Florida PSC order. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income/loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income/loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2014:
 
For Three Months Ended March 31, 2014
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake
Pension SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service cost (credit)
 
$

 
$

 
$
5

 
$
(19
)
 
$

 
(14
)
Net loss
 
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, 2014, we contributed $91,000 and $211,000, to the Chesapeake and FPU pension plans, respectively. We expect to contribute a total of $520,000 and $1.7 million to the Chesapeake and FPU pension plans, respectively, during 2014, which represent the minimum contribution payments required in 2014.
The Chesapeake Pension SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake Pension SERP for the three months

- 17


ended March 31, 2014, were $22,000. We expect to pay total cash benefits of approximately $88,000 under the Chesapeake Pension SERP in 2014. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2014, were $23,000. We have estimated that approximately $95,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2014. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2014, were $55,000. We estimate that approximately $245,000 will be paid for such benefits under the FPU Medical Plan in 2014.

10.
Investments
The investment balances at March 31, 2014 and December 31, 2013, consist of the Rabbi Trusts associated with the 401(k) SERP and deferred compensation plans. We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2014 and 2013, we recorded a net unrealized gain of $37,000 and $283,000, 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. This liability is adjusted each month for the gains and losses incurred by the Rabbi Trusts.
 
11.
Share-Based Compensation
Effective May 2, 2013, our non-employee directors and key employees are awarded share-based awards through our 2013 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, 2014 and 2013:
 
 
 
Three Months Ended
 
 
March 31,
 
 
2014
 
2013
(in thousands)
 
 
 
 
Awards to non-employee directors
 
$
124

 
$
111

Awards to key employees
 
514

 
270

Total compensation expense
 
638

 
381

Less: tax benefit
 
257

 
153

Share-Based Compensation amounts included in net income
 
$
381

 
$
228

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. At March 31, 2014, there was $41,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors’ remaining service periods ending April 30, 2014.


- 18


Key Employees
The table below presents the summary of the stock activity for the awards to key employees for the three months ended March 31, 2014:
 
 
 
Number of Shares
 
Weighted Average
Fair Value
Outstanding—December 31, 2013
 
80,761

 
$
42.30

Granted
 
27,628

 
$
58.35

Vested
 
26,364

 
$
40.30

Outstanding—March 31, 2014
 
82,025

 
$
48.35

In January and March 2014, the Board of Directors granted awards of 27,628 shares to key employees under the SICP. The award of 23,200 shares granted in January 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2016. The award of 4,428 shares granted in March 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2015. These 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, 2014, the aggregate intrinsic value of the SICP awards was $5.2 million.
 

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 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 in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2014, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

In June 2013, Sharp entered into put options to protect against the decline in propane prices and related potential inventory losses associated with 1.3 million gallons purchased for the propane price cap program in the upcoming heating season. If exercised, we would have received the difference between the market price and the strike price if propane prices had fallen below the strike prices of $0.830 per gallon in December 2013 through February of 2014, and $0.860 per gallon in January through March 2014. We accounted for these options as fair value hedges, and there is no ineffective portion of these hedges. We paid $120,000 to purchase the put options, which expired without exercise as the market prices exceeded the strike prices.

In May 2013, Sharp entered into a call option to protect against an increase in propane prices associated with 630,000 gallons expected to be purchased at market-based prices to supply the demands of our propane price cap program customers. The program caps the retail price that we can charge to those customers during the upcoming heating season at a pre-determined level. The call option is exercised if the propane prices rise above the strike price of $0.975 per gallon in January through March of 2014. We accounted for this call option as a derivative instrument on a mark-to-market basis with any change in its fair value being reflected in current period earnings. We paid $72,000 to purchase the call option. In January through March of 2014, we received $209,000 representing the difference between the market price and the strike price during those months.
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, 2014, we did not have outstanding trading contracts.
 
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

- 19


payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2014, Xeron had a right to offset $5.3 million and $3.8 million of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2013, Xeron had a right to offset $2.8 million and $3.2 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.
Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013, are as follows: 
 
 
Asset Derivatives
 
 
 
 
Fair Value As Of
(in thousands)
 
Balance Sheet Location
 
March 31, 2014
 
December 31, 2013
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Forward contracts
 
Mark-to-market energy assets
 
$

 
$
196

Call Option (1)
 
Mark-to-market energy assets
 

 
169

Derivatives designated as fair value hedges
 
 
 
 
 
 
        Put Options (2)
 
Mark-to-market energy assets
 

 
20

Total asset derivatives
 
 
 
$

 
$
385

 
 
 
Liability Derivatives
 
 
 
 
Fair Value As Of
(in thousands)
 
Balance Sheet Location
 
March 31, 2014
 
December 31, 2013
Derivatives not designated as hedging instruments
 
 
 
 
 
 
Forward contracts
 
Mark-to-market energy liabilities
 
$

 
$
127

Total liability derivatives
 
 
 
$

 
$
127

 
(1) 
We purchased a call option for the propane price cap program in May 2013. The call option was fully exercised during 2014. There was no outstanding call option at March 31, 2014.
(2) 
We purchased put options for the propane price cap program in June 2013. The put options expired in March 2014.

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
 
2014
 
2013
Derivatives not designated as hedging instruments:
 
 
 
 
 
 
Unrealized gain (loss) on forward contracts
 
Revenue
 
$
(68
)
 
214

Call Option
 
Cost of sales
 
137

 

Derivatives designated as fair value hedges:
 
 
 
 
 
 
Put/Call Options
 
Cost of sales
 
(20
)
 
(28
)
Total
 
 
 
$
49

 
$
186


- 20


The effects of trading activities on the condensed consolidated statements of income are the following:
 
 
 
Location in the
 
For the Three Months Ended March 31,
(in thousands)
 
Statements of Income
 
2014
 
2013
Realized gain on forward contracts
 
Revenue
 
$
1,246

 
$
74

Unrealized gain (loss) on forward contracts
 
Revenue
 
(68
)
 
214

Total
 
 
 
$
1,178

 
$
288

 
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).

We did not have mark-to-market energy assets or liabilities at March 31, 2014. 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 used at March 31, 2014 and December 31, 2013:
 
 
 
 
 
Fair Value Measurements Using:
March 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
 
$
365

 
$

 
$

 
$
365

Investments—other
 
$
2,586

 
$
2,586

 
$

 
$

 
 
 
 
 
Fair Value Measurements Using:
December 31, 2013
(in thousands)
 
Fair Value
 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
Assets:
 
 
 
 
 
 
 
 
Investments—guaranteed income fund
 
$
458

 
$

 
$

 
$
458

Investments—other
 
$
2,640

 
$
2,640

 
$

 
$

Mark-to-market energy assets, incl. put/call options
 
$
385

 
$

 
$
385

 
$

Liabilities:
 
 
 
 
 
 
 
 
Mark-to-market energy liabilities
 
$
127

 
$

 
$
127

 
$



- 21


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, 2014 and 2013:
 
 
Three Months Ended 
 March 31,
 
2014
 
2013
(in thousands)
 
 
 
Beginning Balance
$
458

 
$

Transfers in due to change in trustee

 
425

Purchases and adjustments
(94
)
 
(13
)
Transfers

 
(16
)
Investment income
1

 
2

Ending Balance
$
365

 
$
398


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

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2014 and December 31, 2013:
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—The fair value of the propane put/call options 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.

At March 31, 2014, 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, 2014, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $121.2 million. This compares to a fair value of $137.9 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, 2013, long-term debt, including the current maturities but excludes a capital lease obligation, had a carrying value of $122.0 million, compared to the estimated fair value of $136.8 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.


- 22


14.
Long-Term Debt
Our outstanding long-term debt is shown below:
 
 
 
March 31,
 
December 31,
(in thousands)
 
2014
 
2013
FPU secured first mortgage bonds (A) :
 
 
 
 
9.08% bond, due June 1, 2022
 
$
7,967

 
$
7,967

Uncollateralized senior notes:
 
 
 
 
7.83% note, due January 1, 2015
 
2,000

 
2,000

6.64% note, due October 31, 2017
 
10,909

 
10,909

5.50% note, due October 12, 2020
 
14,000

 
14,000

5.93% note, due October 31, 2023
 
30,000

 
30,000

5.68% note, due June 30, 2026
 
29,000

 
29,000

6.43% note, due May 2, 2028
 
7,000

 
7,000

3.73% note, due December 16, 2028
 
20,000

 
20,000

Convertible debentures:
 
 
 
 
8.25% due March 1, 2014
 

 
646

Promissory notes
 
360

 
445

Capital lease obligation
 
6,914

 
6,978

Total long-term debt
 
128,150

 
128,945

Less: current maturities
 
(10,955
)
 
(11,353
)
Total long-term debt, net of current maturities
 
$
117,195

 
$
117,592


(A) 
FPU secured first mortgage bonds are guaranteed by Chesapeake.
    
Uncollateralized Senior Notes
In September 2013, we entered into a Note Agreement to issue $70.0 million in aggregate of unsecured Senior Notes to the Note Holders. In December 2013, we issued Series A Notes of unsecured Senior Notes, with an aggregate principal amount of $20.0 million, at a rate of 3.73 percent. Series B of the unsecured Senior Notes, with an aggregate principal amount of $50.0 million, will be issued on May 15, 2014, at a rate of 3.88 percent. The proceeds received from the issuances of the Notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.

Convertible Debentures
During the first two months of 2014, Convertible Debentures totaling $537,000 were converted to stock and $109,000 were redeemed for cash. As of March 1, 2014, we no longer have any outstanding Convertible Debentures.


- 23


Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2013, including the audited consolidated financial statements and notes thereto.
Safe Harbor for Forward-Looking Statements
We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks, uncertainties and other important factors that could cause actual results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:

state and federal legislative and regulatory initiatives (including deregulation) that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries;
the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the costs associated with such matters are adequately covered by insurance or recovered in rates;
the loss of customers due to a government-mandated sale of our utility distribution facilities;
industrial, commercial and residential growth or contraction in our markets or service territories;
the weather and other natural phenomena, including the economic, operational and other effects of hurricanes, ice storms and other damaging weather events;
the timing and extent of changes in commodity prices and interest rates;
general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;
changes in environmental and other laws and regulations to which we are subject and changes in environmental conditions of property that we now or may in the future own or operate;
the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;
the impact to the asset values and resulting higher costs and funding obligations of the Company's pension and other postretirement benefit plans as a result of potential downturns in the financial markets, lower discount rates or impacts associated with the Patient Protection and Affordable Care Act;
the creditworthiness of counterparties with which we are engaged in transactions;
the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;
the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;
the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;
the ability to establish and maintain new key supply sources;
the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;
the effect of competition on our businesses;
the ability to construct facilities at or below estimated costs;
risks related to cyber-attack or failure of information technology systems; and

- 24


changes in technology affecting our advanced information services business.
Introduction
We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in regulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services.
Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;
expanding the regulated energy distribution and transmission businesses into new geographic areas and providing new services in our current service territories;
expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;
expanding both our regulated energy and unregulated energy businesses through strategic acquisitions;
utilizing our expertise across our various businesses to improve overall performance;
pursuing and entering new unregulated energy markets and business lines that will complement our existing strategy and operating units;
enhancing marketing channels to attract new customers;
providing reliable and responsive customer service to existing customers so they become our best promoters;
engaging our customers through a distinctive service excellence initiative;
developing and retaining a high-performing team that advances our goals;
empowering and engaging our employees at all levels to live our brand and vision;
demonstrating community leadership and engaging our local communities and governments in a cooperative and mutually beneficial way;
maintaining a capital structure that enables us to access capital as needed;
maintaining a consistent and competitive dividend for shareholders; and
creating and maintaining a diversified customer base, energy portfolio and utility foundation.
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 normally highest due to colder temperatures.
The following discussions and those elsewhere in the document on operating income and segment results include the use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structure for non-regulated segments. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.


- 25


Results of Operations For Three Months Ended March 31, 2014
Overview and Highlights
Our net income for the three months ended March 31, 2014 was $17.7 million, or $1.82 per share (diluted). This represents an increase of $2.8 million, or $0.28 per share (diluted), compared to net income of $14.9 million, or $1.54 per share (diluted), as reported for the same quarter in 2013.
 
 
 
Three Months Ended
 
 
 
 
March 31,
 
Increase
 
 
2014
 
2013
 
(decrease)
(in thousands except per share)
 
 
 
 
 
 
Business Segment:
 
 
 
 
 
 
Regulated Energy
 
$
21,091

 
$
17,306

 
$
3,785

Unregulated Energy
 
10,858

 
9,369

 
1,489

Other
 
(326
)
 
(125
)
 
(201
)
Operating Income
 
31,623

 
26,550

 
5,073

Other Income
 
6

 
289

 
(283
)
Interest Charges
 
2,155

 
2,072

 
83

Income Taxes
 
11,793

 
9,898

 
1,895

Net Income
 
$
17,681

 
$
14,869

 
$
2,812

Earnings Per Share of Common Stock
 
 
 
 
 
 
Basic
 
$
1.83

 
$
1.55

 
$
0.28

Diluted
 
$
1.82

 
$
1.54

 
$
0.28


































- 26


Key variances included: 
(in thousands, except per share)
 
Pre-tax
Income
 
Net
Income
 
Earnings
Per Share
First Quarter of 2013 Reported Results
 
$
24,767

 
$
14,869

 
$
1.54

Adjusting for unusual items:
 
 
 
 
 
 
Weather impact (due primarily to colder temperatures in 2014)
 
2,711

 
1,628

 
0.17

 
 
2,711

 
1,628

 
0.17

Increased (Decreased) Gross Margins:
 
 
 
 
 
 
Major Projects (See Major Projects Highlights table)
 
 
 
 
 
 
Contribution from Sandpiper
 
4,289

 
2,575

 
0.27

Service expansions
 
1,423

 
855

 
0.08

Increased wholesale propane sales
 
1,032

 
620

 
0.06

Propane wholesale marketing
 
889

 
534

 
0.06

GRIP
 
724

 
435

 
0.04

Lower retail propane margins
 
(516
)
 
(310
)
 
(0.03
)
Contribution from other acquisitions
 
502

 
302

 
0.03

 
 
8,343

 
5,011

 
0.51

Increased Other Operating Expenses:
 
 
 
 
 
 
Expenses from acquisitions
 
(2,117
)
 
(1,271
)
 
(0.14
)
Higher payroll costs
 
(1,161
)
 
(697
)
 
(0.07
)
Increased accruals for incentive compensation
 
(980
)
 
(589
)
 
(0.06
)
Higher depreciation, asset removal and property tax costs due to new capital investments
 
(726
)
 
(436
)
 
(0.04
)
Higher benefits costs
 
(674
)
 
(405
)
 
(0.04
)
 
 
(5,658
)
 
(3,398
)
 
(0.35
)
Net Other Changes
 
(689
)