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EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORPcpk9302016ex-322.htm
EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORPcpk9302016ex-321.htm
EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORPcpk9302016ex-312.htm
EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORPcpk9302016ex-311.htm
EX-3.3 - EXHIBIT 3.3 - CHESAPEAKE UTILITIES CORPcpk9302016ex-33.htm

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
 
 
 
 
FORM 10-Q
 
 
 
 

x
QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2016
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
 
x
  
Accelerated filer
 
¨
 
 
 
 
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 $0.486716,301,161 shares outstanding as of October 31, 2016.



Table of Contents
 




GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities into which Gatherco merged on April 1, 2015
CDD: Cooling degree-day, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit
Chesapeake or Chesapeake Utilities: 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 Utilities
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake Utilities
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake Utilities
CHP: A combined heat and power plant constructed by Eight Flags on Amelia Island, Florida
Columbia Gas: Columbia Gas of Ohio
Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Credit Agreement: The Credit Agreement dated October 8, 2015, among Chesapeake Utilities and the Lenders related to the Revolver
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
Delaware Division: Chesapeake Utilities' natural gas distribution operation serving customers in Delaware
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 Utilities
EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of ESG
Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC
EPA: United States Environmental Protection Agency
ESG: Eastern Shore Gas Company and its affiliates
FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission, an independent agency of the United States government that regulates the interstate transmission of electricity, natural gas, and oil
FDEP: Florida Department of Environmental Protection
FDOT: Florida Department of Transportation



FGT: Florida Gas Transmission Company
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities
FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake Utilities
FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake Utilities
GAAP: Accounting principles generally accepted in the United States of America
Gatherco: Gatherco, Inc., a corporation that merged with and into Aspire Energy on April 1, 2015
GRIP: The Gas Reliability Infrastructure Program is a natural gas pipeline replacement program in Florida, pursuant to which we collect a surcharge from certain of our Florida customers to recover capital and other program-related costs associated with the replacement of qualifying distribution mains and services in Florida
Gulf Power: Gulf Power Company
Gulfstream: Gulfstream Natural Gas System, LLC
HDD: Heating degree-day, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit
JEA: The community-owned utility located in Jacksonville, Florida, formerly known as Jacksonville Electric Authority
Lenders: PNC, Bank of America N.A., Citizens Bank N.A., Royal Bank of Canada, and Wells Fargo Bank, National Association, which are collectively the lenders that entered into the Credit Agreement
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
OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, an Eastern Shore firm transportation service that allows Eastern Shore not to schedule service for up to 90 days during the peak months of November through April
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned Florida intrastate pipeline subsidiary of Chesapeake Utilities
PESCO: Peninsula Energy Services Company, Inc., a wholly-owned natural gas marketing subsidiary of Chesapeake Utilities
PNC: PNC Bank, National Association, the administrative agent and primary lender for our Revolver
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Shelf Agreement for the potential future purchase of our Shelf Notes
PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake Utilities’ natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida
RAP: Remedial Action Plan, which is a plan that outlines the procedures taken or being considered in removing contaminants from a MGP formerly owned by Chesapeake Utilities or FPU
Revolver: Our unsecured revolving credit facility with the Lenders
Retirement Savings Plan: Chesapeake Utilities' qualified 401(k) retirement savings plan
Sandpiper: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities providing a tariff-based distribution service to customers in Worcester County, Maryland



Sanford Group: FPU and other responsible parties involved with the Sanford environmental site
SCO supplier agreement: Standard Choice Offer (SCO) supplier agreement between PESCO and Columbia Gas
SEC: Securities and Exchange Commission
Sharp: Sharp Energy, Inc., a wholly-owned propane distribution subsidiary of Chesapeake Utilities
Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, by October 8, 2018, up to $150.0 million of Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
Shelf Notes: Unsecured senior promissory notes that we may request Prudential to purchase under the Shelf Agreement
SICP: 2013 Stock and Incentive Compensation Plan
SIR: A system improvement rate adder designed to fund system expansion costs in Sandpiper Energy’s service territories
TETLP: Texas Eastern Transmission, LP
Xeron: Xeron, Inc., a propane wholesale marketing subsidiary of Chesapeake Utilities



PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
 
 
Three Months Ended
 
Nine Months Ended
 
 
 
September 30,
 
September 30,
 
 
 
2016
 
2015
 
2016
 
2015
 
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
 
Operating Revenues
 
 
 
 
 
 
 
 
 
Regulated Energy
 
$
70,019

 
$
63,796

 
$
226,630

 
$
235,438

 
Unregulated Energy and other
 
38,329

 
28,117

 
130,356

 
119,238

 
Total Operating Revenues
 
108,348

 
91,913

 
356,986

 
354,676

 
Operating Expenses
 
 
 
 
 
 
 
 
 
Regulated Energy cost of sales
 
24,644

 
23,161

 
81,184

 
101,414

 
Unregulated Energy and other cost of sales
 
28,183

 
17,959

 
85,142

 
73,465

 
Operations
 
30,126

 
26,388

 
85,370

 
79,522

 
Maintenance
 
3,542

 
2,603

 
8,925

 
8,033

 
Gain from a settlement
 

 

 
(130
)
 
(1,500
)
 
Depreciation and amortization
 
8,209

 
7,636

 
23,493

 
22,155

 
Other taxes
 
3,488

 
3,257

 
10,725

 
10,000

 
Total Operating Expenses
 
98,192

 
81,004

 
294,709

 
293,089

 
Operating Income
 
10,156

 
10,909

 
62,277

 
61,587

 
Other (expense) income, net
 
(28
)
 
36

 
(68
)
 
(3
)
 
Interest charges
 
2,722

 
2,492

 
7,996

 
7,425

 
Income Before Income Taxes
 
7,406

 
8,453

 
54,213


54,159

 
Income taxes
 
2,990

 
3,334

 
21,401

 
21,638

 
Net Income
 
$
4,416

 
$
5,119

 
$
32,812


$
32,521

 
Weighted Average Common Shares Outstanding:
 
 
 
 
 
 
 
 
 
Basic
 
15,372,413

 
15,258,819

 
15,324,932

 
15,035,569

 
Diluted
 
15,412,783

 
15,306,843

 
15,365,955

 
15,083,641

 
Earnings Per Share of Common Stock:
 
 
 
 
 
 
 
 
 
Basic
 
$
0.29

 
$
0.34

 
$
2.14

 
$
2.16

 
Diluted
 
$
0.29

 
$
0.33

 
$
2.14

 
$
2.16

 
Cash Dividends Declared Per Share of Common Stock
 
$
0.3050

 
$
0.2875

 
$
0.8975

 
$
0.8450

 
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
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
(in thousands)
 
 
 
 
 
 
 
 
Net Income
 
$
4,416

 
$
5,119

 
$
32,812

 
$
32,521

Other Comprehensive Income (Loss), net of tax:
 
 
 
 
 
 
 
 
Employee Benefits, net of tax:
 
 
 
 
 
 
 
 
Amortization of prior service cost, net of tax of $(8), $(7), $(23) and $(20), respectively
 
(12
)
 
(10
)
 
(37
)
 
(30
)
Net gain, net of tax of $66, $62, $200 and $187, respectively
 
100

 
93

 
300

 
278

Cash Flow Hedges, net of tax:
 
 
 
 
 
 
 
 
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $38, $(51), $360 and $(29), respectively
 
51

 
(75
)
 
548

 
(43
)
Total Other Comprehensive Income
 
139

 
8

 
811

 
205

Comprehensive Income
 
$
4,555

 
$
5,127

 
$
33,623

 
$
32,726

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


- 2


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets
 
September 30,
2016
 
December 31,
2015
(in thousands, except shares and per share data)
 
 
 
 
Property, Plant and Equipment
 
 
 
 
Regulated Energy
 
$
908,822

 
$
842,756

Unregulated Energy
 
194,743

 
145,734

Other businesses and eliminations
 
20,835

 
18,999

Total property, plant and equipment
 
1,124,400

 
1,007,489

Less: Accumulated depreciation and amortization
 
(237,434
)
 
(215,313
)
Plus: Construction work in progress
 
49,082

 
62,774

Net property, plant and equipment
 
936,048

 
854,950

Current Assets
 
 
 
 
Cash and cash equivalents
 
1,536

 
2,855

Accounts receivable (less allowance for uncollectible accounts of $792 and $909, respectively)
 
47,103

 
41,007

Accrued revenue
 
9,506

 
12,452

Propane inventory, at average cost
 
4,106

 
6,619

Other inventory, at average cost
 
3,867

 
3,803

Regulatory assets
 
6,045

 
8,268

Storage gas prepayments
 
8,192

 
3,410

Income taxes receivable
 
13,178

 
24,950

Prepaid expenses
 
7,603

 
7,146

Mark-to-market energy assets
 
477

 
153

Other current assets
 
543

 
1,044

Total current assets
 
102,156

 
111,707

Deferred Charges and Other Assets
 
 
 
 
Goodwill
 
15,070

 
14,548

Other intangible assets, net
 
1,938

 
2,222

Investments, at fair value
 
4,630

 
3,644

Regulatory assets
 
76,343

 
77,519

Receivables and other deferred charges
 
4,325

 
2,831

Total deferred charges and other assets
 
102,306

 
100,764

Total Assets
 
$
1,140,510

 
$
1,067,421

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

- 3


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities
 
September 30,
2016
 
December 31,
2015
(in thousands, except shares and per share data)
 
 
 
 
Capitalization
 
 
 
 
Stockholders’ equity
 
 
 
 
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding
 
$

 
$

Common stock, par value $0.4867 per share (authorized 25,000,000 shares)
 
7,932

 
7,432

Additional paid-in capital
 
250,202

 
190,311

Retained earnings
 
185,195

 
166,235

Accumulated other comprehensive loss
 
(5,029
)
 
(5,840
)
Deferred compensation obligation
 
2,476

 
1,883

Treasury stock
 
(2,476
)
 
(1,883
)
Total stockholders’ equity
 
438,300

 
358,138

Long-term debt, net of current maturities
 
143,525

 
149,006

Total capitalization
 
581,825

 
507,144

Current Liabilities
 
 
 
 
Current portion of long-term debt
 
12,087

 
9,151

Short-term borrowing
 
154,490

 
173,397

Accounts payable
 
41,297

 
39,300

Customer deposits and refunds
 
26,858

 
27,173

Accrued interest
 
3,119

 
1,311

Dividends payable
 
4,678

 
4,390

Accrued compensation
 
7,823

 
10,014

Regulatory liabilities
 
2,412

 
7,365

Mark-to-market energy liabilities
 
29

 
433

Other accrued liabilities
 
10,260

 
7,059

Total current liabilities
 
263,053

 
279,593

Deferred Credits and Other Liabilities
 
 
 
 
Deferred income taxes
 
205,562

 
192,600

Regulatory liabilities
 
43,354

 
43,064

Environmental liabilities
 
8,682

 
8,942

Other pension and benefit costs
 
32,501

 
33,481

Deferred investment tax credits and other liabilities
 
5,533

 
2,597

Total deferred credits and other liabilities
 
295,632

 
280,684

Environmental and other commitments and contingencies (Note 5 and 6)
 

 

Total Capitalization and Liabilities
 
$
1,140,510

 
$
1,067,421

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


- 4


Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 
 
Nine Months Ended
 
 
September 30,
 
 
2016
 
2015
(in thousands)
 
 
 
 
Operating Activities
 
 
 
 
Net income
 
$
32,812

 
$
32,521

Adjustments to reconcile net income to net cash provided by operating activities:
 
 
 
 
Depreciation and amortization
 
23,493

 
22,155

Depreciation and accretion included in other costs
 
5,357

 
5,280

Deferred income taxes, net
 
12,004

 
(1,155
)
Realized gain on commodity contracts/sale of assets/investments
 
(405
)
 
(411
)
Unrealized (gain) loss on investments/commodity contracts
 
(243
)
 
60

Employee benefits and compensation
 
1,217

 
901

Share-based compensation
 
1,887

 
1,445

Other, net
 
42

 
13

Changes in assets and liabilities:
 
 
 
 
Accounts receivable and accrued revenue
 
(3,835
)
 
21,898

Propane inventory, storage gas and other inventory
 
(2,179
)
 
3,166

Regulatory assets/liabilities, net
 
(3,326
)
 
6,467

Prepaid expenses and other current assets
 
485

 
(159
)
Accounts payable and other accrued liabilities
 
3,679

 
(9,897
)
Income taxes receivable
 
14,897

 
14,883

Customer deposits and refunds
 
(314
)
 
(1,177
)
Accrued compensation
 
(2,293
)
 
(1,406
)
Other assets and liabilities, net
 
(1,053
)
 
(652
)
Net cash provided by operating activities
 
82,225

 
93,932

Investing Activities
 
 
 
 
Property, plant and equipment expenditures
 
(106,851
)
 
(97,299
)
Proceeds from sales of assets
 
119

 
109

Acquisitions, net of cash acquired
 

 
(20,930
)
Environmental expenditures
 
(260
)
 
(113
)
Net cash used in investing activities
 
(106,992
)
 
(118,233
)
Financing Activities
 
 
 
 
Common stock dividends
 
(12,964
)
 
(11,725
)
Issuance of stock for Dividend Reinvestment Plan
 
600

 
633

Stock issuance
 
57,306

 

Change in cash overdrafts due to outstanding checks
 
2,466

 
2,964

Net (repayment) borrowing under line of credit agreements
 
(21,379
)
 
35,898

Repayment of long-term debt and capital lease obligation
 
(2,581
)
 
(4,262
)
Net cash provided by financing activities
 
23,448

 
23,508

Net Decrease in Cash and Cash Equivalents
 
(1,319
)
 
(793
)
Cash and Cash Equivalents—Beginning of Period
 
2,855

 
4,574

Cash and Cash Equivalents—End of Period
 
$
1,536

 
$
3,781

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 (2)
Balance at December 31, 2014
14,588,711

 
$
7,100

 
$
156,581

 
$
142,317

 
$
(5,676
)
 
$
1,258

 
$
(1,258
)
 
$
300,322

Net income
 
 

 

 
41,140

 

 

 

 
41,140

Other comprehensive loss

 

 

 

 
(164
)
 

 

 
(164
)
Dividend declared ($1.1325 per share)

 

 

 
(17,222
)
 

 

 

 
(17,222
)
Retirement savings plan and dividend reinvestment plan
43,275

 
21

 
2,214

 

 

 

 

 
2,235

Common stock issued in acquisition
592,970

 
289

 
29,876

 

 

 

 

 
30,165

Share-based compensation and tax benefit (4) (5)
45,703

 
22

 
1,640

 

 

 

 

 
1,662

Treasury stock activities

 

 

 

 

 
625

 
(625
)
 

Balance at December 31, 2015
15,270,659

 
7,432

 
190,311

 
166,235

 
(5,840
)
 
1,883

 
(1,883
)
 
358,138

Net income

 

 

 
32,812

 

 

 

 
32,812

Other comprehensive income

 

 

 

 
811

 

 

 
811

Dividend declared ($0.8975 per share)

 

 

 
(13,852
)
 

 

 

 
(13,852
)
Retirement savings plan and dividend reinvestment plan
30,041

 
15

 
1,859

 

 

 

 

 
1,874

Stock issuance (3)
960,488

 
467

 
56,839

 

 

 

 

 
57,306

Share-based compensation and tax benefit (4) (5)
36,099

 
18

 
1,193

 

 

 

 

 
1,211

Treasury stock activities

 

 

 

 

 
593

 
(593
)
 

Balance at September 30, 2016
16,297,287

 
$
7,932

 
$
250,202

 
$
185,195

 
$
(5,029
)
 
$
2,476

 
$
(2,476
)
 
$
438,300

 
(1) 
Includes 80,024 and 70,631 shares at September 30, 2016 and December 31, 2015, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.
(2) 
2,000 shares of preferred stock at $0.00001 par value has been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.
(3) 
On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.3 million.
(4) 
Includes amounts for shares issued for Directors’ compensation.
(5) 
The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, 2016, and for the year ended December 31, 2015, we withheld 12,031 and 12,620 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 Utilities,” “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, 2015. 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 reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015. We have revised the condensed consolidated statement of cash flows for the nine months ended September 30, 2015 to reflect only property, plant and equipment expenditures paid in cash within the Investing Activities section.  The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section. These revisions are considered immaterial to the overall presentation of our condensed consolidated financial statements.
On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.3 million, which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.

FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
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 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $301,000 and $333,000 at September 30, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities, in our condensed consolidated balance sheets.

Intangibles-Goodwill and Other-Internal-Use Software (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations.

Interest-Imputation of Interest (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Presentation and Subsequent Measurement of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position or results of operations.

Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments and requires that the cumulative impact of a measurement-period adjustments (including

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the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations.

Income Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet by eliminating the current deferred income taxes asset and decreasing the noncurrent deferred income taxes liability by $831,000.

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. In March 2016, FASB issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for 2018 interim and annual financial statements. We have engaged a third party to review our contracts with customers and to aid in assessing the impact this standard may have on our financial position and results of operations.
Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations.
Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations.

Compensation-Stock Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

Statement of Cash Flows (ASC 230) - On August 26, 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We are assessing the impact of the adoption of this ASU on our statements of cash flows.
 


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2.
Calculation of Earnings Per Share

 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
(in thousands, except shares and per share data)
 
 
 
 
 
 
 
 
Calculation of Basic Earnings Per Share:
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Net Income
 
$
4,416

 
$
5,119

 
$
32,812

 
$
32,521

Weighted average shares outstanding
 
15,372,413

 
15,258,819

 
15,324,932

 
15,035,569

Basic Earnings Per Share
 
$
0.29

 
$
0.34

 
$
2.14

 
$
2.16

 
 
 
 
 
 
 
 
 
Calculation of Diluted Earnings Per Share:
 
 
 
 
 
 
 
 
Reconciliation of Numerator:
 
 
 
 
 
 
 
 
Net Income
 
$
4,416

 
$
5,119

 
32,812

 
32,521

Reconciliation of Denominator:
 
 
 
 
 
 
 
 
Weighted shares outstanding—Basic
 
15,372,413

 
15,258,819

 
15,324,932

 
15,035,569

Effect of dilutive securities:
 
 
 
 
 
 
 
 
Share-based compensation
 
40,370

 
48,024

 
41,023

 
48,072

Adjusted denominator—Diluted
 
15,412,783

 
15,306,843

 
15,365,955

 
15,083,641

Diluted Earnings Per Share
 
$
0.29

 
$
0.33

 
$
2.14

 
$
2.16

 

3.
Acquisitions
Gatherco Merger
On April 1, 2015, we completed the merger in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio.  The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative, which together serve more than 20,000 end-use customers.  Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services so that it can maintain service quality and reliability for its wholesale markets.
At closing, we issued 592,970 shares of our common stock, valued at $30.2 million, based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of outstanding Gatherco debt, which we paid off on the closing date. We also acquired $6.8 million of cash on hand at closing.
(in thousands)
Net Purchase Price
Chesapeake Utilities common stock
$
30,164

Cash
27,494

Acquired debt
1,696

Aggregate amount paid in the acquisition
59,354

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

The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities during the five-year period following the closing. As of September 30, 2016, there have been no related gathering opportunities developed; therefore, no contingent consideration liability has been recorded.  Based on the absence of related gathering opportunities being developed as of September 30, 2016, we are unable to estimate the range of undiscounted contingent liability outcomes at this time.

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We incurred $1.3 million in transaction costs associated with this merger of which we incurred $786,000 in 2014 and the remaining $514,000 in 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net loss from this merger for the three months ended September 30, 2016, included in our condensed consolidated statements of income, were $5.6 million and $563,000, respectively. The revenue and net income from this merger for the nine months ended September 30, 2016, included in our condensed consolidated statements of income, were $18.4 million and $1.1 million, respectively. This merger was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share for such period.
The purchase price allocation of the Gatherco merger was as follows:
 
Purchase price
(in thousands)
Allocation
Purchase price
$
57,658

 
 
Property plant and equipment
53,203

Cash
6,806

Accounts receivable
3,629

Income taxes receivable
3,163

Other assets
425

Total assets acquired
67,226

 
 
Long-term debt
1,696

Deferred income taxes
13,409

Accounts payable
3,837

Other current liabilities
745

Total liabilities assumed
19,687

Net identifiable assets acquired
47,539

Goodwill
$
10,119

The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the merger date. The goodwill primarily reflects the value paid for opportunities for growth in a new, strategic geographic area. All of the goodwill from this merger was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes.
In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to $10.1 million after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.

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 Utilities' 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
Rate Case Filing: On December 21, 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of approximately $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue normalization mechanism for residential and small commercial customers.

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We expect a decision on the application during the first quarter of 2017. Pending the decision, our Delaware Division increased rates on an interim basis based on the $2.5 million annualized interim rates approved by the Delaware PSC, effective February 19, 2016 ("Phase I"). We recognized incremental revenue of approximately $469,000 ($280,000 net of tax) and $1.4 million ($817,000 net of tax) for the three and nine months ended September 30, 2016, respectively.
In addition, our Delaware Division requested and received approval on July 26, 2016, from the Delaware PSC to implement revised interim rates totaling $4.7 million (equal to the initial rate increase in our application) annualized for usage on and after August 1, 2016 ("Phase II"). These revised interim rates represent a five-percent increase over Phase I rates. Revenue associated with these rates collected prior to a final Delaware PSC decision is subject to refund and, although the final decision is expected during the first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast the timing of a final decision. Consequently, we will not recognize the impact of the potential additional revenue related to the Phase II rate increase until the Delaware PSC issues its approval in a final ruling.
Maryland
Sandpiper Rate Case Filing: On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $950,000, or approximately five- percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue normalization mechanism for residential and small commercial customers. The procedural schedule was suspended in early May 2016 to allow for the continuation of settlement discussions between Sandpiper, Maryland PSC Staff and the Maryland Office of People's Counsel. The parties reached a settlement agreement, which Sandpiper filed with the Commission on August 10, 2016. The terms of the agreement include revenue neutral rates for the first year, followed by a schedule of rate reductions in subsequent years based upon the projected rate of propane to natural gas conversions. A revenue normalization mechanism and stratification of rate classes were also included in the settlement agreement. On September 28, 2016, the Public Utility Law Judge issued a proposed order recommending approval of the settlement terms. The order became final on October 29, 2016 and the new rates will be in effect on December 1, 2016.
Florida
On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time.

On February 2, 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held April 5, 2016.

On April 11, 2016, FPU’s natural gas divisions and Chesapeake Utilities' Florida division filed a joint petition for approval to allow FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchased gas adjustment and operational balancing account, which is currently allocated to a limited number of customers. The expanded allocation of these costs includes additional customers, primarily transportation customers, benefiting from these costs but not currently paying for them. This petition was approved by the Florida PSC at its Agenda Conference in September 2016.

Eastern Shore
White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERCseeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator 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.

On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route and shortened the total miles of the proposed pipeline to 5.4 miles. On February 10, 2016, the FERC issued a notice combining the White Oak Mainline Expansion Project and the System Reliability Project into a single environmental assessment.

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On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed White Oak Mainline Project. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment in the certificate proceeding. However, FERC’s determination is without prejudice to Eastern Shore filing for and fully supporting rolled-in rate treatment of these project facilities in a future general rate case. The certificate required Eastern Shore to comply with 19 environmental conditions.

On July 29, 2016, Eastern Shore accepted the certificate of public convenience and necessity and, on August 2, 2016, filed its Implementation Plan to comply with each environmental condition and to request approval to begin construction. On August 4, 2016, the FERC issued a “Notice to Proceed,” and Eastern Shore commenced construction during August 2016. Eastern Shore continues to file weekly status reports in compliance with one of the environmental conditions.
System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project.
On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. The FERC granted Eastern Shore’s request for a pre-determination of rolled-in rate treatment in its next rate base proceeding and required Eastern Shore to comply with 19 environmental conditions.

On July 29, 2016, Eastern Shore accepted the certificate and on August 5, 2016 filed its Implementation Plan to comply with each environmental condition and to request approval to begin construction. On August 12, 2016, the FERC issued a “Partial Notice to Proceed” approving construction for certain portions of the System Reliability Project. On September 15, 2016, the FERC granted approval to start construction on the remaining portion of the Project. Construction commenced on the Bridgeville Compressor Station and the Porter Road Loop in August 2016, and on the Dover Loop, in September 2016 and is ongoing. Eastern Shore continues to file weekly status reports in compliance with one of the environmental conditions.
TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.
2017 Expansion Project: On May 12, 2016, Eastern Shore submitted a request to the FERC to initiate the FERC’s pre-filing review procedures for Eastern Shore's 2017 expansion project. The expansion project consists of approximately 33 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional 3,550 horsepower compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. The expansion project is necessary to provide up to 86,437 Dts/d of additional firm natural gas transportation capacity to meet anticipated market demand. On May 17, 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore is currently working through the pre-filing process and anticipates filing, in December 2016, its application for a certificate of public convenience and necessity, seeking authorization to construct the expansion facilities.
Since the time the pre-filing was initiated, Eastern Shore has finalized market participation for the project. Seven of Eastern Shore’s existing customers have signed Precedent Agreements. As a result, the project will provide 61,162 Dts/d of additional firm natural gas transportation deliverability on Eastern Shore’s pipeline system. To provide this additional capacity, the project’s final facilities will consist of approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional 3,550 horsepower compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County,

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Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware.
2017 Rate Case Filing
In January 2017, Eastern Shore intends to file a base rate proceeding with the FERC, as required by the terms of its 2012 settlement agreement.



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.
MGP Sites
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 discussing with the MDE another former MGP site located in Cambridge, Maryland.
As of September 30, 2016, we had approximately $9.9 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $10.5 million of which has been recovered as of September 30, 2016, leaving approximately $3.5 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $298,000 in environmental liabilities at September 30, 2016, representing our estimate of future costs associated with Chesapeake Utilities' MGP site in Winter Haven, Florida.
During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' 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 Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of September 30, 2016, we had approximately $156,000 in environmental liabilities and $267,000 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 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. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. We received a letter dated January 6, 2016 from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.
We expect 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.


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Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which is the site on which a former MGP that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP previously located on this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of September 30, 2016, 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 remedial 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 advised the other members of the Sanford Group that it is unwilling to pay any sum in excess of the $650,000 paid by FPU under the Third Participation Agreement. The Sanford Group has not requested that FPU contribute to costs beyond the originally agreed upon $650,000 contribution.
As of September 30, 2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. 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 as to its limited liability for future costs exceeding $13.0 million to implement the final remedy for this site, as provided for in the Third Participation Agreement, or whether the other members of the Sanford Group will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid pursuant to the Third Participation Agreement. No such claims have been made as of September 30, 2016.

Key West, Florida
FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual NAM. The most recent groundwater-monitoring event was conducted in September 2016. Natural attenuation default criteria were met at all locations sampled and the semi-annual report was submitted on October 4, 2016 with the recommendation that semi-annual monitoring should continue at this facility. The next semi-annual NAM is scheduled for the first quarter of 2017.
Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.
Pensacola, Florida
FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.


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Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.
Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.
Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $425,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site.
FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP. Therefore, we have not recorded a liability for sediment remediation.
Salisbury, Maryland
We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. As directed by MDE, additional measures were performed and this last remaining well was redeveloped in September 2016. Depending on future observations, additional testing may be required. We anticipate that the remaining costs for maintaining and monitoring this one remaining well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission this well.
Seaford, Delaware
In a letter dated December 5, 2013, DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. On September 17, 2015, DNREC approved our application to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and the resulting remedial investigation report was submitted to DNREC in May 2016. Based on findings from the remedial investigation, DNREC requested additional investigative work be performed prior to approval of potential remedial actions. We anticipate completing this additional investigative work by the end of the second quarter of 2017. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000.

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Cambridge, Maryland
We are discussing with the MDE 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.
Ohio
We have completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. Under the merger agreement, we are entitled to be indemnified from an escrow fund created at closing for certain matters, including certain claims related to environmental remediation. The costs incurred to date associated with remediation activities for these eight facilities is approximately $1.6 million. In September 2016, we and the Gatherco shareholder agent resolved certain disputes associated with our claims for indemnification, including claims for environmental matters. After deducting the amount of anticipated tax benefits related to our claims and an indemnification deductible in the amount of $431,250 in accordance with the merger agreement, we received a total of approximately $500,000 from the indemnification escrow in payment of our claims with no material impact to our financial statements.  We do not anticipate submitting any additional claims for indemnification or receiving any additional indemnification payments related to or arising out of the Gatherco merger.

6.
Other Commitments and Contingencies
Natural Gas, Electric and Propane Supply
We have entered into contractual commitments to purchase natural 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, 2017.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term ending in May 2019. 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 ending in May 2019. 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 Utilities' 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 Utilities is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2016, 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 and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is $65.0 million.

- 16


Chesapeake Utilities has issued corporate guarantees to certain of our subsidiaries' vendors, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 2016 was approximately $53.9 million, with the guarantees expiring on various dates through September 2017.
Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this 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).
We issued letters of credit totaling approximately $8.4 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through September 2017. There have been no draws on these letters of credit as of September 30, 2016. 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.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of September 30, 2016 and December 31, 2015, we maintained a liability of approximately $50,000 related to unrecognized income tax benefits. As of December 31, 2015, we maintained a liability of approximately $310,000 related to contingencies for taxes other than income. We did not have a liability related to contingencies for taxes other than income at September 30, 2016.
Other
We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

7.
Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise two reportable segments:
Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy, whose services include natural gas gathering, processing, transportation and supply (See Note 3, Acquisitions, regarding the merger with Gatherco). Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. 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.
The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.


- 17


The following table presents financial information about our reportable segments:
 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
(in thousands)
 
 
 
 
 
 
 
 
Operating Revenues, Unaffiliated Customers
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
68,899

 
$
63,526

 
$
224,382

 
$
234,608

Unregulated Energy segment
 
39,449

 
28,387

 
132,604

 
120,068

Total operating revenues, unaffiliated customers
 
$
108,348

 
$
91,913

 
$
356,986

 
$
354,676

Intersegment Revenues (1)
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
1,120

 
$
270

 
$
2,248

 
$
830

Unregulated Energy segment
 
2,593

 
1,222

 
3,759

 
3,095

Other businesses
 
240

 
220

 
705

 
660

Total intersegment revenues
 
$
3,953

 
$
1,712

 
$
6,712

 
$
4,585

Operating Income
 
 
 
 
 
 
 
 
Regulated Energy segment
 
$
13,115

 
$
11,828

 
$
52,660

 
$
47,616

Unregulated Energy segment
 
(3,080
)
 
(1,022
)
 
9,267

 
13,666

Other businesses and eliminations
 
121

 
103

 
350

 
305

Total operating income
 
10,156

 
10,909

 
62,277

 
61,587

Other (expense) income, net
 
(28
)
 
36

 
(68
)
 
(3
)
Interest
 
2,722

 
2,492

 
7,996

 
7,425

Income before Income Taxes
 
7,406

 
8,453

 
54,213

 
54,159

Income taxes
 
2,990

 
3,334

 
21,401

 
21,638

Net Income
 
$
4,416

 
$
5,119

 
$
32,812

 
$
32,521

 
(1) 
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands)
 
September 30, 2016
 
December 31, 2015
Identifiable Assets
 
 
 
 
Regulated Energy segment
 
$
921,682

 
$
872,065

Unregulated Energy segment
 
207,083

 
171,840

Other businesses and eliminations
 
11,745

 
23,516

Total identifiable assets
 
$
1,140,510

 
$
1,067,421


Our operations are entirely domestic.
 

- 18


8.
Accumulated Other Comprehensive Loss
Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, 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 nine months ended September 30, 2016 and 2015. 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, 2015
 
$
(5,580
)
 
$
(260
)
 
$
(5,840
)
Other comprehensive gain before reclassifications
 

 
641

 
641

Amounts reclassified from accumulated other comprehensive loss
 
263

 
(93
)
 
170

Net current-period other comprehensive income
 
263

 
548

 
811

As of September 30, 2016
 
$
(5,317
)
 
$
288

 
$
(5,029
)

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

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

 
33

 
281

Net prior-period other comprehensive income
 
248

 
(43
)
 
205

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

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2016 and 2015. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Gains or losses for our commodity contracts fair value hedges are recognized immediately in earnings.

- 19


 
 
Three Months Ended
 
Nine Months Ended
 
 
September 30,
 
September 30,
 
 
2016
 
2015
 
2016
 
2015
(in thousands)
 
 
 
 
 
 
 
 
Amortization of defined benefit pension and postretirement plan items:
 
 
 
 
 
 
 
 
Prior service cost (1)
 
$
20

 
$
17

 
$
60

 
$
50

Net loss (1)
 
(166
)
 
(155
)
 
(500
)
 
(465
)
Total before income taxes
 
(146
)

(138
)
 
(440
)

(415
)
Income tax benefit
 
58

 
55

 
177

 
167

Net of tax
 
$
(88
)
 
$
(83
)
 
$
(263
)

$
(248
)
 
 
 
 
 
 
 
 
 
Gains and losses on commodity contracts cash flow hedges
 
 
 
 
 
 
 
 
Propane swap agreements (2)
 
$

 
$

 
$
(322
)
 
$

Call options (2)
 

 

 

 
(55
)
Natural gas futures (2)
 
105

 

 
464

 

Total before income taxes
 
105

 

 
142


(55
)
Income tax benefit (expense)
 
(41
)
 

 
(49
)
 
22

Net of tax
 
64

 


93

 
(33
)
Total reclassifications for the period
 
$
(24
)
 
$
(83
)

$
(170
)
 
$
(281
)
 
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.
Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements and call options are included in cost of sales, in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

9.
Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2016 and 2015 are set forth in the following tables:
 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Three Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
105

 
$
102

 
$
635

 
$
626

 
$
23

 
$
23

 
$
11

 
$
11

 
$
14

 
$
15

Expected return on plan assets
 
(131
)
 
(135
)
 
(625
)
 
(777
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 

 
2

 
(20
)
 
(19
)
 

 

Amortization of net loss
 
103

 
91

 
133

 
114

 
22

 
25

 
16

 
17

 

 
2

Net periodic cost (benefit)
 
77

 
58

 
143

 
(37
)
 
45

 
50

 
7

 
9

 
14

 
17

Amortization of pre-merger regulatory asset
 

 

 
191

 
191

 

 

 

 

 
2

 
2

Total periodic cost
 
$
77

 
$
58

 
$
334

 
$
154

 
$
45

 
$
50

 
$
7

 
$
9


$
16

 
$
19


- 20


 
 
Chesapeake
Pension Plan
 
FPU
Pension Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Nine Months Ended September 30,
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
 
2016
 
2015
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Interest cost
 
$
315

 
$
306

 
$
1,894

 
$
1,877

 
$
68

 
$
68

 
$
32

 
$
33

 
$
41

 
$
45

Expected return on plan assets
 
(392
)
 
(405
)
 
(2,027
)
 
(2,330
)
 

 

 

 

 

 

Amortization of prior service cost
 

 

 

 

 

 
8

 
(60
)
 
(58
)
 

 

Amortization of net loss
 
309

 
272

 
389

 
341

 
66

 
74

 
51

 
53

 

 
5

Net periodic cost (benefit)
 
232

 
173

 
256

 
(112
)
 
134

 
150

 
23

 
28

 
41

 
50

Amortization of pre-merger regulatory asset
 

 

 
571

 
571

 

 

 

 

 
6

 
6

Total periodic cost
 
$
232

 
$
173

 
$
827

 
$
459

 
$
134

 
$
150

 
$
23

 
$
28

 
$
47

 
$
56


We expect to record pension and postretirement benefit costs of approximately $1.7 million for 2016. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $2.3 million and approximately $2.9 million at September 30, 2016 and December 31, 2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of approximately $917,000, which will increase our total expected benefit costs to approximately $1.7 million.
Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.
The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended September 30, 2016 and 2015:
 
For the Three Months Ended September 30, 2016
 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 
Chesapeake SERP
 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 
Total
(in thousands)
 
 
 
 
 
 
 
 
 
 
 
 
Prior service credit
 
$

 
$

 
$

 
$
(20
)
 
$

 
$
(20
)
Net loss
 
103

 
133

 
22

 
16

 

 
274

Total recognized in net periodic benefit cost
 
$
103

 
$
133

 
$
22

 
$
(4
)
 
$

 
$
254

Recognized from accumulated other comprehensive loss (1)
 
$
103

 
$
25

 
$
22

 
$
(4
)
 
$

 
$
146