UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
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x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended: September 30, 20162017
OR
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¨ | 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
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CHESAPEAKE UTILITIES CORPORATION (Exact name of registrant as specified in its charter) |
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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):
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Large accelerated filer | | x | | Accelerated filer | | ¨ |
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Non-accelerated filer | | ¨ | | Smaller reporting company | | ¨ |
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Common Stock, par value $0.4867 — 16,301,16116,344,442 shares outstanding as of October 31, 20162017.
Table of Contents
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ITEM 1. | | |
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ITEM 2. | | |
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ITEM 3. | | |
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ITEM 4. | | |
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ITEM 1. | | |
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ITEM 1A. | | |
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ITEM 2. | | |
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ITEM 3. | | |
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ITEM 5. | | |
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ITEM 6. | | |
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GLOSSARY OF DEFINITIONS
ARM: ARM Energy Management, LLC, a natural gas supply and supply management company servicing commercial and industrial customers in Western Pennsylvania, which sold certain natural gas marketing assets to PESCO in August 2017
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 thea 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 direct and indirect 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
Chipola: Chipola Propane Gas Company, Inc., a propane distribution service provider in Northwest Florida, which sold certain assets to Flo-gas in August 2017
CIAC: Contributions from customers that are used to construct facilities
CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative
CHP: A combinedCombined heat and power plant constructed by Eight Flags on Amelia Island, Florida
Columbia Gas: Columbia Gas of Ohio, an unaffiliated local distribution company based in Ohio
Company: Chesapeake Utilities Corporation, its divisions and its direct and indirect subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and Necessity
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
Degree-Day: A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit
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
Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value
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, which owns and operates a CHP plant on Amelia Island, Florida
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
Flo-gas: Flo-gas Corporation, a wholly-owned subsidiary of FPU
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, an unaffiliated electric company that supplies electricity to FPU
Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU
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 unaffiliated 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 with Chesapeake Utilities
MDE: Maryland Department of Environment
MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we entered into the MetLife Shelf Agreement
MetLife Shelf Agreement: An agreement entered into by Chesapeake Utilities and MetLife in March 2017 pursuant to which Chesapeake Utilities may request that MetLife purchase, through March 2, 2020, up to $150.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
NAM:MWH: Natural Attenuation MonitoringMegawatt hour, which is a unit of measurement for electricity
NYSE: NYL:New York Stock ExchangeLife Investors LLC, an institutional debt investment management firm, with which we entered into the NYL Shelf Agreement
NYL Shelf Agreement: An agreement entered into by Chesapeake Utilities and NYL in March 2017 pursuant to which Chesapeake Utilities may request that NYL purchase, through March 2, 2020, up to $100.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, ana tariff associated with Eastern ShoreShore's firm transportation service that allowsenables Eastern Shore not to scheduleforgo scheduling service for up to 90 days during the peak months of November through April each year
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., aChesapeake Utilities' wholly-owned Florida intrastate pipeline subsidiary of Chesapeake Utilities
PESCO: Peninsula Energy Services Company, Inc., aChesapeake Utilities' 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 Prudential Shelf Agreement for
Prudential Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, through October 7, 2018, up to $150.0 million of Prudential Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the potential futuredate of issuance
Prudential Shelf Notes: Unsecured senior promissory notes that we may request Prudential to purchase of ourunder the Prudential Shelf NotesAgreement
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
Revolver: Our unsecured revolving credit facility with the Lenders
Rights Plan: A plan designed to protect against abusive or coercive takeover attempts or tactics that are contrary to the best interests of Chesapeake Utilities' stockholders
Sandpiper: Sandpiper Energy, Inc., aChesapeake Utilities' wholly-owned subsidiary, of Chesapeake Utilities providingwhich provides a tariff-based distribution service to customers in Worcester County, Maryland
Sanford Group: FPU and other responsible parties involved with the Sanford environmentalMGP site
SCO supplier agreement: Standard Choice Offer (SCO) supplier agreement between PESCO and Columbia Gas
SEC: Securities and Exchange Commission
Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
Sharp: Sharp Energy, Inc., aChesapeake Utilities' 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, an interstate pipeline interconnected with Eastern Shore's pipeline
Xeron: Xeron, Inc., a propane wholesale marketingan inactive subsidiary of Chesapeake Utilities, which previously engaged in propane and crude oil trading
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 | | | Three Months Ended | | Nine Months Ended | |
| | September 30, | | September 30, | | | September 30, | | September 30, | |
| | 2016 | | 2015 | | 2016 | | 2015 | | | 2017 | | 2016 | | 2017 | | 2016 | |
(in thousands, except shares and per share data) | | | | | | | | | | | | | | | | | | |
Operating Revenues | | | | | | | | | | | | | | | | | | |
Regulated Energy | | $ | 70,019 |
| | $ | 63,796 |
| | $ | 226,630 |
| | $ | 235,438 |
| | | $ | 69,703 |
| | $ | 70,019 |
| | $ | 238,353 |
| | $ | 226,630 |
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Unregulated Energy and other | | 38,329 |
| | 28,117 |
| | 130,356 |
| | 119,238 |
| | | 57,233 |
| | 38,329 |
| | 198,827 |
| | 130,356 |
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Total Operating Revenues | | 108,348 |
| | 91,913 |
| | 356,986 |
| | 354,676 |
| | | 126,936 |
| | 108,348 |
| | 437,180 |
| | 356,986 |
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Operating Expenses | | | | | | | | | | | | | | | | | | |
Regulated Energy cost of sales | | 24,644 |
| | 23,161 |
| | 81,184 |
| | 101,414 |
| | | 22,794 |
| | 24,644 |
| | 87,206 |
| | 81,184 |
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Unregulated Energy and other cost of sales | | 28,183 |
| | 17,959 |
| | 85,142 |
| | 73,465 |
| | | 44,066 |
| | 28,183 |
| | 145,325 |
| | 85,142 |
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Operations | | 30,126 |
| | 26,388 |
| | 85,370 |
| | 79,522 |
| | | 29,667 |
| | 30,126 |
| | 92,990 |
| | 85,370 |
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Maintenance | | 3,542 |
| | 2,603 |
| | 8,925 |
| | 8,033 |
| | | 2,737 |
| | 3,542 |
| | 9,370 |
| | 8,925 |
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Gain from a settlement | | — |
| | — |
| | (130 | ) | | (1,500 | ) | | | — |
| | — |
| | (130 | ) | | (130 | ) | |
Depreciation and amortization | | 8,209 |
| | 7,636 |
| | 23,493 |
| | 22,155 |
| | | 9,362 |
| | 8,209 |
| | 27,267 |
| | 23,493 |
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Other taxes | | 3,488 |
| | 3,257 |
| | 10,725 |
| | 10,000 |
| | | 4,071 |
| | 3,488 |
| | 12,572 |
| | 10,725 |
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Total Operating Expenses | | 98,192 |
| | 81,004 |
| | 294,709 |
| | 293,089 |
| | | 112,697 |
| | 98,192 |
| | 374,600 |
| | 294,709 |
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Operating Income | | 10,156 |
| | 10,909 |
| | 62,277 |
| | 61,587 |
| | | 14,239 |
| | 10,156 |
| | 62,580 |
| | 62,277 |
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Other (expense) income, net | | (28 | ) | | 36 |
| | (68 | ) | | (3 | ) | | |
Other income (expense), net | | | 239 |
| | (28 | ) | | (643 | ) | | (68 | ) | |
Interest charges | | 2,722 |
| | 2,492 |
| | 7,996 |
| | 7,425 |
| | | 3,321 |
| | 2,722 |
| | 9,133 |
| | 7,996 |
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Income Before Income Taxes | | 7,406 |
| | 8,453 |
| | 54,213 |
|
| 54,159 |
| | | 11,157 |
| | 7,406 |
| | 52,804 |
|
| 54,213 |
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Income taxes | | 2,990 |
| | 3,334 |
| | 21,401 |
| | 21,638 |
| | | 4,324 |
| | 2,990 |
| | 20,781 |
| | 21,401 |
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Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | $ | 32,812 |
|
| $ | 32,521 |
| | | $ | 6,833 |
| | $ | 4,416 |
| | $ | 32,023 |
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| $ | 32,812 |
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Weighted Average Common Shares Outstanding: | | | | | | | | | | | | | | | | | | |
Basic | | 15,372,413 |
| | 15,258,819 |
| | 15,324,932 |
| | 15,035,569 |
| | | 16,344,442 |
| | 15,372,413 |
| | 16,334,210 |
| | 15,324,932 |
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Diluted | | 15,412,783 |
| | 15,306,843 |
| | 15,365,955 |
| | 15,083,641 |
| | | 16,389,635 |
| | 15,412,783 |
| | 16,378,633 |
| | 15,365,955 |
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Earnings Per Share of Common Stock: | | | | | | | | | | | | | | | | | | |
Basic | | $ | 0.29 |
| | $ | 0.34 |
| | $ | 2.14 |
| | $ | 2.16 |
| | | $ | 0.42 |
| | $ | 0.29 |
| | $ | 1.96 |
| | $ | 2.14 |
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Diluted | | $ | 0.29 |
| | $ | 0.33 |
| | $ | 2.14 |
| | $ | 2.16 |
| | | $ | 0.42 |
| | $ | 0.29 |
| | $ | 1.96 |
| | $ | 2.14 |
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Cash Dividends Declared Per Share of Common Stock | | $ | 0.3050 |
| | $ | 0.2875 |
| | $ | 0.8975 |
| | $ | 0.8450 |
| | | $ | 0.3250 |
| | $ | 0.3050 |
| | $ | 0.9550 |
| | $ | 0.8975 |
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The accompanying notes are an integral part of these financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | $ | 32,812 |
| | $ | 32,521 |
| | $ | 6,833 |
| | $ | 4,416 |
| | $ | 32,023 |
| | $ | 32,812 |
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Other Comprehensive Income (Loss), net of tax: | | | | | | | | | |
Other Comprehensive (Loss) Income, 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 |
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Amortization of prior service cost, net of tax of $(8), $(8), $(23) and $(23), respectively | | | (11 | ) | | (12 | ) | | (35 | ) | | (37 | ) |
Net gain, net of tax of $69, $66, $212 and $200, respectively | | | 102 |
| | 100 |
| | 297 |
| | 300 |
|
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 |
| |
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(15), $38, $(376) and $360, respectively | | | (104 | ) | | 51 |
| | (643 | ) | | 548 |
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Total Other Comprehensive (Loss) Income | | | (13 | ) | | 139 |
| | (381 | ) | | 811 |
|
Comprehensive Income | | $ | 4,555 |
| | $ | 5,127 |
| | $ | 33,623 |
| | $ | 32,726 |
| | $ | 6,820 |
| | $ | 4,555 |
| | $ | 31,642 |
| | $ | 33,623 |
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The accompanying notes are an integral part of these financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
| | Assets | | September 30, 2016 | | December 31, 2015 | | September 30, 2017 | | December 31, 2016 |
(in thousands, except shares and per share data) | | | | | | | | |
Property, Plant and Equipment | | | | | | | | |
Regulated Energy | | $ | 908,822 |
| | $ | 842,756 |
| | $ | 1,050,332 |
| | $ | 957,681 |
|
Unregulated Energy | | 194,743 |
| | 145,734 |
| | 207,331 |
| | 196,800 |
|
Other businesses and eliminations | | 20,835 |
| | 18,999 |
| | 26,061 |
| | 21,114 |
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Total property, plant and equipment | | 1,124,400 |
| | 1,007,489 |
| | 1,283,724 |
| | 1,175,595 |
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Less: Accumulated depreciation and amortization | | (237,434 | ) | | (215,313 | ) | | (267,138 | ) | | (245,207 | ) |
Plus: Construction work in progress | | 49,082 |
| | 62,774 |
| | 69,053 |
| | 56,276 |
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Net property, plant and equipment | | 936,048 |
| | 854,950 |
| | 1,085,639 |
| | 986,664 |
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Current Assets | | | | | | | | |
Cash and cash equivalents | | 1,536 |
| | 2,855 |
| | 3,386 |
| | 4,178 |
|
Accounts receivable (less allowance for uncollectible accounts of $792 and $909, respectively) | | 47,103 |
| | 41,007 |
| |
Accounts receivable (less allowance for uncollectible accounts of $912 and $909, respectively) | | | 52,775 |
| | 62,803 |
|
Accrued revenue | | 9,506 |
| | 12,452 |
| | 14,307 |
| | 16,986 |
|
Propane inventory, at average cost | | 4,106 |
| | 6,619 |
| | 5,226 |
| | 6,457 |
|
Other inventory, at average cost | | 3,867 |
| | 3,803 |
| | 12,711 |
| | 4,576 |
|
Regulatory assets | | 6,045 |
| | 8,268 |
| | 9,761 |
| | 7,694 |
|
Storage gas prepayments | | 8,192 |
| | 3,410 |
| | 6,876 |
| | 5,484 |
|
Income taxes receivable | | 13,178 |
| | 24,950 |
| | 26,741 |
| | 22,888 |
|
Prepaid expenses | | 7,603 |
| | 7,146 |
| | 10,899 |
| | 6,792 |
|
Mark-to-market energy assets | | 477 |
| | 153 |
| |
Derivative assets, at fair value | | | 1,526 |
| | 823 |
|
Other current assets | | 543 |
| | 1,044 |
| | 4,797 |
| | 2,470 |
|
Total current assets | | 102,156 |
| | 111,707 |
| | 149,005 |
| | 141,151 |
|
Deferred Charges and Other Assets | | | | | | | | |
Goodwill | | 15,070 |
| | 14,548 |
| | 21,944 |
| | 15,070 |
|
Other intangible assets, net | | 1,938 |
| | 2,222 |
| | 4,608 |
| | 1,843 |
|
Investments, at fair value | | 4,630 |
| | 3,644 |
| | 6,380 |
| | 4,902 |
|
Regulatory assets | | 76,343 |
| | 77,519 |
| | 75,793 |
| | 76,803 |
|
Receivables and other deferred charges | | 4,325 |
| | 2,831 |
| | 3,381 |
| | 2,786 |
|
Total deferred charges and other assets | | 102,306 |
| | 100,764 |
| | 112,106 |
| | 101,404 |
|
Total Assets | | $ | 1,140,510 |
| | $ | 1,067,421 |
| | $ | 1,346,750 |
| | $ | 1,229,219 |
|
The accompanying notes are an integral part of these financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
| | Capitalization and Liabilities | | September 30, 2016 | | December 31, 2015 | | September 30, 2017 | | December 31, 2016 |
(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 |
| | 7,955 |
| | 7,935 |
|
Additional paid-in capital | | 250,202 |
| | 190,311 |
| | 252,722 |
| | 250,967 |
|
Retained earnings | | 185,195 |
| | 166,235 |
| | 208,402 |
| | 192,062 |
|
Accumulated other comprehensive loss | | (5,029 | ) | | (5,840 | ) | | (5,259 | ) | | (4,878 | ) |
Deferred compensation obligation | | 2,476 |
| | 1,883 |
| | 3,366 |
| | 2,416 |
|
Treasury stock | | (2,476 | ) | | (1,883 | ) | | (3,366 | ) | | (2,416 | ) |
Total stockholders’ equity | | 438,300 |
| | 358,138 |
| | 463,820 |
| | 446,086 |
|
Long-term debt, net of current maturities | | 143,525 |
| | 149,006 |
| | 201,248 |
| | 136,954 |
|
Total capitalization | | 581,825 |
| | 507,144 |
| | 665,068 |
| | 583,040 |
|
Current Liabilities | | | | | | | | |
Current portion of long-term debt | | 12,087 |
| | 9,151 |
| | 12,136 |
| | 12,099 |
|
Short-term borrowing | | 154,490 |
| | 173,397 |
| | 203,098 |
| | 209,871 |
|
Accounts payable | | 41,297 |
| | 39,300 |
| | 53,284 |
| | 56,935 |
|
Customer deposits and refunds | | 26,858 |
| | 27,173 |
| | 32,493 |
| | 29,238 |
|
Accrued interest | | 3,119 |
| | 1,311 |
| | 3,361 |
| | 1,312 |
|
Dividends payable | | 4,678 |
| | 4,390 |
| | 5,312 |
| | 4,973 |
|
Accrued compensation | | 7,823 |
| | 10,014 |
| | 8,544 |
| | 10,496 |
|
Regulatory liabilities | | 2,412 |
| | 7,365 |
| | 5,338 |
| | 1,291 |
|
Mark-to-market energy liabilities | | 29 |
| | 433 |
| |
Derivative liabilities, at fair value | | | 1,732 |
| | 773 |
|
Other accrued liabilities | | 10,260 |
| | 7,059 |
| | 13,972 |
| | 7,063 |
|
Total current liabilities | | 263,053 |
| | 279,593 |
| | 339,270 |
| | 334,051 |
|
Deferred Credits and Other Liabilities | | | | | | | | |
Deferred income taxes | | 205,562 |
| | 192,600 |
| | 252,273 |
| | 222,894 |
|
Regulatory liabilities | | 43,354 |
| | 43,064 |
| | 42,915 |
| | 43,064 |
|
Environmental liabilities | | 8,682 |
| | 8,942 |
| | 8,382 |
| | 8,592 |
|
Other pension and benefit costs | | 32,501 |
| | 33,481 |
| | 32,059 |
| | 32,828 |
|
Deferred investment tax credits and other liabilities | | 5,533 |
| | 2,597 |
| | 6,783 |
| | 4,750 |
|
Total deferred credits and other liabilities | | 295,632 |
| | 280,684 |
| | 342,412 |
| | 312,128 |
|
Environmental and other commitments and contingencies (Note 5 and 6) | |
| |
| |
Environmental and other commitments and contingencies (Note 4 and 5) | | |
| |
|
Total Capitalization and Liabilities | | $ | 1,140,510 |
| | $ | 1,067,421 |
| | $ | 1,346,750 |
| | $ | 1,229,219 |
|
The accompanying notes are an integral part of these financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
| | | | Nine Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2016 | | 2015 | | 2017 | | 2016 |
(in thousands) | | | | | | | | |
Operating Activities | | | | | | | | |
Net income | | $ | 32,812 |
| | $ | 32,521 |
| | $ | 32,023 |
| | $ | 32,812 |
|
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | | | | |
Depreciation and amortization | | 23,493 |
| | 22,155 |
| | 27,267 |
| | 23,493 |
|
Depreciation and accretion included in other costs | | 5,357 |
| | 5,280 |
| | 5,989 |
| | 5,357 |
|
Deferred income taxes, net | | 12,004 |
| | (1,155 | ) | |
Deferred income taxes | | | 29,520 |
| | 12,004 |
|
Realized gain on commodity contracts/sale of assets/investments | | (405 | ) | | (411 | ) | | (2,817 | ) | | (405 | ) |
Unrealized (gain) loss on investments/commodity contracts | | (243 | ) | | 60 |
| |
Unrealized gain on investments/commodity contracts | | | (695 | ) | | (243 | ) |
Employee benefits and compensation | | 1,217 |
| | 901 |
| | 1,212 |
| | 1,217 |
|
Share-based compensation | | 1,887 |
| | 1,445 |
| | 1,608 |
| | 1,887 |
|
Other, net | | 42 |
| | 13 |
| | (39 | ) | | 42 |
|
Changes in assets and liabilities: | | | | | | | | |
Accounts receivable and accrued revenue | | (3,835 | ) | | 21,898 |
| | 12,912 |
| | (3,835 | ) |
Propane inventory, storage gas and other inventory | | (2,179 | ) | | 3,166 |
| | (8,256 | ) | | (2,179 | ) |
Regulatory assets/liabilities, net | | (3,326 | ) | | 6,467 |
| | 927 |
| | (3,326 | ) |
Prepaid expenses and other current assets | | 485 |
| | (159 | ) | | (2,860 | ) | | 485 |
|
Accounts payable and other accrued liabilities | | 3,679 |
| | (9,897 | ) | | 4,515 |
| | 7,187 |
|
Income taxes receivable | | 14,897 |
| | 14,883 |
| |
Income taxes (payable) receivable | | | (3,810 | ) | | 14,897 |
|
Customer deposits and refunds | | (314 | ) | | (1,177 | ) | | 3,255 |
| | (314 | ) |
Accrued compensation | | (2,293 | ) | | (1,406 | ) | | (2,030 | ) | | (2,293 | ) |
Other assets and liabilities, net | | (1,053 | ) | | (652 | ) | | (349 | ) | | (1,053 | ) |
Net cash provided by operating activities | | 82,225 |
| | 93,932 |
| | 98,372 |
| | 85,733 |
|
Investing Activities | | | | | | | | |
Property, plant and equipment expenditures | | (106,851 | ) | | (97,299 | ) | | (130,137 | ) | | (109,589 | ) |
Proceeds from sales of assets | | 119 |
| | 109 |
| | 601 |
| | 119 |
|
Acquisitions, net of cash acquired | | — |
| | (20,930 | ) | | (11,707 | ) | | — |
|
Environmental expenditures | | (260 | ) | | (113 | ) | | (210 | ) | | (260 | ) |
Net cash used in investing activities | | (106,992 | ) | | (118,233 | ) | | (141,453 | ) | | (109,730 | ) |
Financing Activities | | | | | | | | |
Common stock dividends | | (12,964 | ) | | (11,725 | ) | | (14,780 | ) | | (12,964 | ) |
Issuance of stock for Dividend Reinvestment Plan | | 600 |
| | 633 |
| | 254 |
| | 600 |
|
Stock issuance | | 57,306 |
| | — |
| | (10 | ) | | 57,306 |
|
Tax withholding payments related to net settled stock compensation | | | (692 | ) | | (770 | ) |
Change in cash overdrafts due to outstanding checks | | 2,466 |
| | 2,964 |
| | (3,013 | ) | | 2,466 |
|
Net (repayment) borrowing under line of credit agreements | | (21,379 | ) | | 35,898 |
| |
Net repayment under line of credit agreements | | | (3,760 | ) | | (21,379 | ) |
Proceeds from issuance of long-term debt | | | 69,800 |
| | — |
|
Repayment of long-term debt and capital lease obligation | | (2,581 | ) | | (4,262 | ) | | (5,510 | ) | | (2,581 | ) |
Net cash provided by financing activities | | 23,448 |
| | 23,508 |
| | 42,289 |
| | 22,678 |
|
Net Decrease in Cash and Cash Equivalents | | (1,319 | ) | | (793 | ) | | (792 | ) | | (1,319 | ) |
Cash and Cash Equivalents—Beginning of Period | | 2,855 |
| | 4,574 |
| | 4,178 |
| | 2,855 |
|
Cash and Cash Equivalents—End of Period | | $ | 1,536 |
| | $ | 3,781 |
| | $ | 3,386 |
| | $ | 1,536 |
|
The accompanying notes are an integral part of these financial statements.
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
| | | Common Stock | | | | | | | | | | | | | Common Stock (1) | | | | | | | | | | | | |
(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) | Number of Shares(2) | | 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 |
| 15,270,659 |
| | $ | 7,432 |
| | $ | 190,311 |
| | $ | 166,235 |
| | $ | (5,840 | ) | | $ | 1,883 |
| | $ | (1,883 | ) | | $ | 358,138 |
|
Net income | — |
| | — |
| | — |
| | 32,812 |
| | — |
| | — |
| | — |
| | 32,812 |
| — |
| | — |
| | — |
| | 44,675 |
| | — |
| | — |
| | — |
| | 44,675 |
|
Other comprehensive income | — |
| | — |
| | — |
| | — |
| | 811 |
| | — |
| | — |
| | 811 |
| — |
| | — |
| | — |
| | — |
| | 962 |
| | — |
| | — |
| | 962 |
|
Dividend declared ($0.8975 per share) | — |
| | — |
| | — |
| | (13,852 | ) | | — |
| | — |
| | — |
| | (13,852 | ) | |
Dividend declared ($1.2025 per share) | | — |
| | — |
| | — |
| | (18,848 | ) | | — |
| | — |
| | — |
| | (18,848 | ) |
Retirement savings plan and dividend reinvestment plan | 30,041 |
| | 15 |
| | 1,859 |
| | — |
| | — |
| | — |
| | — |
| | 1,874 |
| 36,253 |
| | 17 |
| | 2,225 |
| | — |
| | — |
| | — |
| | — |
| | 2,242 |
|
Stock issuance (3) | 960,488 |
| | 467 |
| | 56,839 |
| | — |
| | — |
| | — |
| | — |
| | 57,306 |
| 960,488 |
| | 467 |
| | 56,893 |
| | — |
| | — |
| | — |
| | — |
| | 57,360 |
|
Share-based compensation and tax benefit (4) (5) | 36,099 |
| | 18 |
| | 1,193 |
| | — |
| | — |
| | — |
| | — |
| | 1,211 |
| 36,099 |
| | 19 |
| | 1,538 |
| | — |
| | — |
| | — |
| | — |
| | 1,557 |
|
Treasury stock activities | — |
| | — |
| | — |
| | — |
| | — |
| | 593 |
| | (593 | ) | | — |
| — |
| | — |
| | — |
| | — |
| | — |
| | 533 |
| | (533 | ) | | — |
|
Balance at September 30, 2016 | 16,297,287 |
| | $ | 7,932 |
| | $ | 250,202 |
| | $ | 185,195 |
| | $ | (5,029 | ) | | $ | 2,476 |
| | $ | (2,476 | ) | | $ | 438,300 |
| |
Balance at December 31, 2016 | | 16,303,499 |
| | 7,935 |
| | 250,967 |
| | 192,062 |
| | (4,878 | ) | | 2,416 |
| | (2,416 | ) | | 446,086 |
|
Net income | | — |
| | — |
| | — |
| | 32,023 |
| | — |
| | — |
| | — |
| | 32,023 |
|
Other comprehensive loss | | — |
| | — |
| | — |
| | — |
| | (381 | ) | | — |
| | — |
| | (381 | ) |
Dividend declared ($0.9550 per share) | | — |
| | — |
| | — |
| | (15,683 | ) | | — |
| | — |
| | — |
| | (15,683 | ) |
Dividend reinvestment plan | | 10,771 |
| | 5 |
| | 731 |
| | — |
| | — |
| | — |
| | — |
| | 736 |
|
Stock issuance (3) | | — |
| | — |
| | (10 | ) | | — |
| | — |
| | — |
| | — |
| | (10 | ) |
Share-based compensation and tax benefit (4) (5) | | 30,172 |
| | 15 |
| | 1,034 |
| | — |
| | — |
| | — |
| | — |
| | 1,049 |
|
Treasury stock activities | | — |
| | — |
| | — |
| | — |
| | — |
| | 950 |
| | (950 | ) | | — |
|
Balance at September 30, 2017 | | 16,344,442 |
| | $ | 7,955 |
| | $ | 252,722 |
| | $ | 208,402 |
| | $ | (5,259 | ) | | $ | 3,366 |
| | $ | (3,366 | ) | | $ | 463,820 |
|
| |
(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)
| 2,0002,000,000 shares of preferred stock at $0.00001$0.01 par value hashave been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity. |
| |
(2) | Includes 90,588 and 76,745 shares at September 30, 2017 and December 31, 2016, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan. |
| |
(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$57.4 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, 2016,2017, and for the year ended December 31, 20152016, we withheld 12,03110,269 and 12,62012,031 shares, respectively, for taxes. |
The accompanying notes are an integral part of these financial statements.
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, 2015.2016. 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, 20152016 to reflect only property, plant and equipment expenditures paid in cash withinconform to 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.current year’s presentation. These revisionsreclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
On September 22, 2016,Acquisitions
In August 2017, PESCO acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination. The acquired assets complement PESCO’s current asset portfolio and will expand our regional footprint and retail demand in a market where we completedhave existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a public offeringcontingent liability 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$2.5 million, which represents the expected payment of contingent consideration to ARM. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired business and is subject to change based on actual performance or changes in our gross margin projections.
In August 2017, Flo-gas acquired certain operating assets of Chipola, which provides propane distribution service to approximately 800 residential and commercial customers in Jackson, Calhoun, Gadsden, Liberty, Bay and Washington Counties, Florida.
The revenue and net income from these acquisitions that we included in our condensed consolidated statements of income for the three and nine months ended September 30, 2017, were addednot material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.adjustment based on additional valuations performed during the measurement period.
FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
Interest - Imputation of InterestInventory (ASC 835-30)330) - In AprilJuly 2015, the FASB issued ASU 2015-03,2015-11, Simplifying thePresentation Measurement of Debt Issuance CostsInventory. . This standard requires debt issuance costsUnder this guidance, inventories are required to be presented inmeasured at the balance sheet as a direct deduction fromlower of cost or net realizable value. Net realizable value represents the carrying value of theestimated selling price less costs associated debt liability, consistent with the presentation of a debt discount.completion, disposal and transportation. We adopted ASU 2015-03 became effective for us2015-11 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
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 adopted2017, 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 ClassificationTable of Deferred Taxes,Contents
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. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. 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. 2018.
We arehave completed our evaluation of our revenue sources and will continue assessing the impact this standard may have on our financial position, and results of operations.operations and cash flows during the fourth quarter of 2017. In tandem, we have developed and documented accounting policies and position papers, which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. In the third quarter of 2017, we began providing additional training to our employees and implementing system and process changes that are associated with the adoption of the standard. We plan to utilize the modified retrospective transition method upon adoption of this standard.
Based on our current assessment, we believe that the implementation of this new standard will not have a material impact on the amount and timing of revenue recognition except for one long-term contract for which we will delay the recognition of revenue of approximately $407,000 in 2018. Since we have not yet finalized our assessment, we will continue to monitor and subsequently disclose future identified material impacts, if any, in our annual report on Form 10-K for the year ended December 31, 2017. In addition, the AICPA Power and Utilities Industry Task Force is addressing issues specific to our industry, including CIAC, and has concluded that CIAC is outside of the scope of this standard; accordingly, our Regulated Energy segment accounting for CIAC will not change as a result of ASC 606.
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.
We have assessed all of our leases and have concluded that a majority of our operating leases would continue to fall within the category of operating leases; however, we may have some leases that qualify for the short-term lease exception. We will record the right to use of assets and the lease liability related to the operating leases, but we do not believe that this will have a material impact on our financial position, results of operations and cash flows. During the fourth quarter of 2017, we intend to quantify the overall impact that may result from early adoption of the standard and implementation of the overall process. This updateguidance will be applied using athe modified retrospective transition approachmethod 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) - OnIn 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 assessingbelieve that the impact of the adoptionimplementation of this ASUnew standard will not have a material impact on our statementsstatement of cash flows.
Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.
Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and the
capitalization of the service cost is to be applied prospectively on or after the effective date. Aside from changes in presentation, we believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.
Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.
Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations.
| |
2. | Calculation of Earnings Per Share |
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands, except shares and per share data) | | | | | | | | | | | | | | | | |
Calculation of Basic Earnings Per Share: | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | | | |
Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | $ | 32,812 |
| | $ | 32,521 |
| | $ | 6,833 |
| | $ | 4,416 |
| | $ | 32,023 |
| | $ | 32,812 |
|
Weighted average shares outstanding | | 15,372,413 |
| | 15,258,819 |
| | 15,324,932 |
| | 15,035,569 |
| | 16,344,442 |
| | 15,372,413 |
| | 16,334,210 |
| | 15,324,932 |
|
Basic Earnings Per Share | | $ | 0.29 |
| | $ | 0.34 |
| | $ | 2.14 |
| | $ | 2.16 |
| | $ | 0.42 |
| | $ | 0.29 |
| | $ | 1.96 |
| | $ | 2.14 |
|
| | | | | | | | | | | | | | | | |
Calculation of Diluted Earnings Per Share: | | | | | | | | | | | | | | | | |
Reconciliation of Numerator: | | | | | | | | | | | | | | | | |
Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | 32,812 |
| | 32,521 |
| | $ | 6,833 |
| | $ | 4,416 |
| | $ | 32,023 |
| | $ | 32,812 |
|
Reconciliation of Denominator: | | | | | | | | | | | | | | | | |
Weighted shares outstanding—Basic | | 15,372,413 |
| | 15,258,819 |
| | 15,324,932 |
| | 15,035,569 |
| | 16,344,442 |
| | 15,372,413 |
| | 16,334,210 |
| | 15,324,932 |
|
Effect of dilutive securities: | | | | | | | | | |
Share-based compensation | | 40,370 |
| | 48,024 |
| | 41,023 |
| | 48,072 |
| |
Effect of dilutive securities—Share-based compensation | | | 45,193 |
| | 40,370 |
| | 44,423 |
| | 41,023 |
|
Adjusted denominator—Diluted | | 15,412,783 |
| | 15,306,843 |
| | 15,365,955 |
| | 15,083,641 |
| | 16,389,635 |
| | 15,412,783 |
| | 16,378,633 |
| | 15,365,955 |
|
Diluted Earnings Per Share | | $ | 0.29 |
| | $ | 0.33 |
| | $ | 2.14 |
| | $ | 2.16 |
| | $ | 0.42 |
| | $ | 0.29 |
| | $ | 1.96 |
| | $ | 2.14 |
|
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.
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, as separate entities, by the Florida PSC as separate entities.PSC.
Delaware
Rate Case Filing: OnIn 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.
We expect a decision on the application during the first quarter of 2017. Pending the decision, ourThe 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) forStaff, 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 increasePublic Advocate 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,intervenors met 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,in November 2016. The terms of the settlement agreement include revenue neutral rates for the first year, followed by a scheduleincluded an annual increase of rate reductions$2.3 million 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.base rates. The order became final on October 29,in December 2016, and the new rates will bebecame effective January 1, 2017. Amounts collected through interim rates in effect onexcess of the respective portion of the $2.3 million increase through December 1, 2016.31, 2016 were accrued as of that date. In January 2017, we filed our proposed refund plan with the Delaware PSC and subsequently issued refunds to customers in March 2017.
FloridaMaryland
OnThere were no material rates and other regulatory activities for our Maryland division during the period.
Sandpiper
There were no material rates and other regulatory activities for Sandpiper during the period.
Florida
Cost Recovery for the Electric Interconnect Project: In 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 willwould enable FPU's electric division to negotiate a new power purchase agreement that willto mitigate fuel costs for its Northeast division. This actionFPU's proposal was approved by the Florida PSC at its Agenda Conference held onin December 3, 2015. OnIn January 22, 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. LegalThe Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs have been filed, but no decision has been reached at this time.and oral arguments. As a result, FPU excluded the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause and included the costs for recovery in the limited proceeding filing described below.
OnSurcharge Associated with Modernization of Electric Distribution System Project: In February 2, 2016,2017, FPU’s natural gaselectric division filed a petition with the Florida PSC requesting a temporary surcharge mechanism to recover costs and generate an appropriate return on investment associated with an essential reliability and modernization project for its electric distribution system. We requested approval to invest approximately $59.8 million, over a five-year period, associated with the modernization project. In February 2017, the Office of Public Counsel intervened in this petition. The Florida PSC requested that FPU file a limited proceeding to include these investments in base rates instead of seeking approval of an amendment toa temporary surcharge. In April 2017, FPU voluntarily withdrew its existing transportation agreementpetition and subsequently filed the limited proceeding described in the next paragraph.
Electric Limited Proceeding: In July 2017, FPU’s electric division filed a petition 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, atrequesting approval to include $15.2 million of certain capital project expenditures in its Agenda Conference held April 5, 2016.rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system while enhancing the capability of FPU’s grid. Included in the $15.2 million is the interconnection project with Florida Power & Light Company, which enables FPU to mitigate fuel costs for its electric customers. This petition is scheduled for the Florida PSC's December 2017 Agenda.
On April 11, 2016, FPU’sNorthwest Florida Expansion Project: Peninsula Pipeline and FPU's natural gas divisionsdivision are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida division filednatural gas division. We have entered into agreements to serve two large customers and are marketing to other customers close to the facilities.
New Smyrna Beach, Florida Project: Peninsula Pipeline is constructing a joint petition for approval to allowpipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consists of 14 miles of transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and will serve FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchasednatural gas adjustment and operational balancing account, which is currently allocated to a limited number ofdistribution 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,In July 2016, Eastern Shore submitted an application to the FERCseekingreceived FERC 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.Delaware ("White Oak Mainline Project"). Eastern Shore proposes to constructconstructed approximately 7.25.4 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additionalincreased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware.
On November 18, 2015, Eastern Shore filed an amendment At the end of March 2017, the entire project was placed into service. The total cost to this application, which indicatedcomplete 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.project was approximately $42.0 million.
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 toIn September 2016, the FERC seeking authorizationapproved Eastern Shore's application 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 daysPreviously, 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 absent any significant change in its next rate base proceeding and required Eastern Shore to comply with 19 environmental conditions.circumstances.
On July 29, 2016, Eastern Shore acceptedAs of June 2017, 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 expansionentire project was placed into service. The total cost to complete the project was approximately $38.0 million. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund, pending final resolution of the base rate case described below.
2017 Expansion Project: OnIn 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.project (the “2017 Expansion Project”). The expansion project consists of approximately 33 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering2017 Expansion Project's 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 ofinclude 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,
Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. In May 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore entered into Precedent Agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.
In December 2016, Eastern Shore submitted an application for a CP seeking authorization to construct the expansion facilities. Six of Eastern Shore's existing customers timely intervened to become parties. In February and March 2017, Eastern Shore submitted responses to the FERC staff's data requests.
In October 2017, FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 Expansion Project. The estimated cost of the 2017 Expansion Project is approximately $115.0 million
Eastern Shore is preparing its implementation plan, which will be filed with the FERC, addressing the actions Eastern Shore will undertake to meet the Environmental Conditions set forth in the FERC's order. Eastern Shore anticipates placing certain facilities into service by the end of the year and completing the entire project in 2018.
2017 Rate Case Filing
Filing: In January 2017, Eastern Shore intends to filefiled a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.
On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $1.0 million for the three and nine months ended September 30, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case is resolved. Settlement discussions continue among the other parties to the case.
5.4. 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 discussingin discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.
As of September 30, 2016,2017, we had approximately $9.9$9.7 million in environmental liabilities, representing our estimate of the future costs associated with all ofrelated to 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 $10.5sites. Approximately $10.9 million of which has been recovered as of September 30, 2016,2017, leaving approximately $3.5$3.1 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 soilThe following is a summary of our remediation status 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. Estimatedestimated 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 redevelopmentclean-up of the properties.
our MGP sites:
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.
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. |
| | | | |
Jurisdiction | MGP Site | Status | Cost to Clean up | Recovery through Rates |
Florida | West Palm Beach | Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions. | Between $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 | Yes |
Florida | Sanford | In January 2007, FPU and the Sanford group signed a Third Participation Agreement. 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, which has been paid to an escrow account.
The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. | FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000 | Yes |
Florida | Winter Haven | Remediation is ongoing. | Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site | Yes |
Delaware | Seaford | Proposed plan for implementation approved by DNREC in July 2017. | $273,000 to $465,000 | Yes |
Maryland | Cambridge | Currently in discussions with MDE | Unable to estimate | N/A |
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.
| |
6.5. | 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. ForIn 2017, our Delaware and MarylandDelmarva natural gas distribution divisions, we have a contractoperations entered into asset management agreements with an unaffiliated energy marketing and risk management companyPESCO to manage a portion of their natural gas transportation and storage capacity, which expirescapacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2017.2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager.
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 6.52.8 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 6.52.8 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,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, to provide an irrevocable letter of credit.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)percent). If FPU fails to meet either of these ratios,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 also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2016,2017, FPU was in compliance with all of the requirements of its fuel supply contracts.
Corporate Guarantees
Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. In July 2016, Eight Flags also started selling steam an industrial customer that owns the property on which the CHP plant is located pursuant to a separate 20-year contract. The Board of Directors has authorized us to issue corporate guaranteesCHP plant is powered by natural gas transported by FPU through its distribution system 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.Peninsula Pipeline through its intrastate pipeline.
Chesapeake Utilities hasCorporate Guarantees
We have issued corporate guarantees to certain vendors of our subsidiaries' vendors, the largest of which are for Xeron andsubsidiaries, primarily PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiaryPESCO has evernever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 20162017 was approximately $53.9$71.9 million, with the guarantees expiring on various dates through September 2017.2018.
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 1413, Long-Term Debt, for further details).
WeLetters of Credit
As of September 30, 2017, we have issued letters of credit totaling approximately $8.4$5.8 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.June 2018. There have been no draws on these letters of credit as of September 30, 2016.2017. 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.
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 compriseare comprised of 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, andas well as natural gas marketing, gathering, processing, transportation and supply. These 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 inThrough March 2017, this segment are other unregulated energy services, such as energy-related merchandise salesalso included the operations of Xeron, our propane and heating, ventilation and air conditioning, plumbing and electrical services.crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017.
The remainder of ourOther operations isare presented as “Other businesses and eliminations”,eliminations,” which consistsconsist of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.
Our operations are entirely domestic.
The following table presents financial information about our reportable segments:
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Operating Revenues, Unaffiliated Customers | | | | | | | | | | | | | | | | |
Regulated Energy segment | | $ | 68,899 |
| | $ | 63,526 |
| | $ | 224,382 |
| | $ | 234,608 |
| | $ | 67,257 |
| | $ | 68,899 |
| | $ | 232,519 |
| | $ | 224,382 |
|
Unregulated Energy segment | | 39,449 |
| | 28,387 |
| | 132,604 |
| | 120,068 |
| |
Unregulated Energy segment and other businesses | | | 59,679 |
| | 39,449 |
| | 204,661 |
| | 132,604 |
|
Total operating revenues, unaffiliated customers | | $ | 108,348 |
| | $ | 91,913 |
| | $ | 356,986 |
| | $ | 354,676 |
| | $ | 126,936 |
| | $ | 108,348 |
| | $ | 437,180 |
| | $ | 356,986 |
|
Intersegment Revenues (1) | | | | | | | | | | | | | | | | |
Regulated Energy segment | | $ | 1,120 |
| | $ | 270 |
| | $ | 2,248 |
| | $ | 830 |
| | $ | 2,446 |
| | $ | 1,120 |
| | $ | 5,834 |
| | $ | 2,248 |
|
Unregulated Energy segment | | 2,593 |
| | 1,222 |
| | 3,759 |
| | 3,095 |
| | 5,009 |
| | 2,593 |
| | 15,801 |
| | 3,759 |
|
Other businesses | | 240 |
| | 220 |
| | 705 |
| | 660 |
| | 194 |
| | 240 |
| | 581 |
| | 705 |
|
Total intersegment revenues | | $ | 3,953 |
| | $ | 1,712 |
| | $ | 6,712 |
| | $ | 4,585 |
| | $ | 7,649 |
| | $ | 3,953 |
| | $ | 22,216 |
| | $ | 6,712 |
|
Operating Income | | | | | | | | | | | | | | | | |
Regulated Energy segment | | $ | 13,115 |
| | $ | 11,828 |
| | $ | 52,660 |
| | $ | 47,616 |
| | $ | 15,168 |
| | $ | 13,115 |
| | $ | 51,915 |
| | $ | 52,660 |
|
Unregulated Energy segment | | (3,080 | ) | | (1,022 | ) | | 9,267 |
| | 13,666 |
| | (989 | ) | | (3,080 | ) | | 10,504 |
| | 9,267 |
|
Other businesses and eliminations | | 121 |
| | 103 |
| | 350 |
| | 305 |
| | 60 |
| | 121 |
| | 161 |
| | 350 |
|
Total operating income | | 10,156 |
| | 10,909 |
| | 62,277 |
| | 61,587 |
| | 14,239 |
| | 10,156 |
| | 62,580 |
| | 62,277 |
|
Other (expense) income, net | | (28 | ) | | 36 |
| | (68 | ) | | (3 | ) | |
Interest | | 2,722 |
| | 2,492 |
| | 7,996 |
| | 7,425 |
| |
Other income (expense), net | | | 239 |
| | (28 | ) | | (643 | ) | | (68 | ) |
Interest charges | | | 3,321 |
| | 2,722 |
| | 9,133 |
| | 7,996 |
|
Income before Income Taxes | | 7,406 |
| | 8,453 |
| | 54,213 |
| | 54,159 |
| | 11,157 |
| | 7,406 |
| | 52,804 |
|
| 54,213 |
|
Income taxes | | 2,990 |
| | 3,334 |
| | 21,401 |
| | 21,638 |
| | 4,324 |
| | 2,990 |
| | 20,781 |
| | 21,401 |
|
Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | $ | 32,812 |
| | $ | 32,521 |
| | $ | 6,833 |
| | $ | 4,416 |
| | $ | 32,023 |
|
| $ | 32,812 |
|
| |
(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 | | September 30, 2017 | | December 31, 2016 |
Identifiable Assets | | | | | | | | |
Regulated Energy segment | | $ | 921,682 |
| | $ | 872,065 |
| | $ | 1,084,961 |
| | $ | 986,752 |
|
Unregulated Energy segment | | 207,083 |
| | 171,840 |
| | 233,785 |
| | 226,368 |
|
Other businesses and eliminations | | 11,745 |
| | 23,516 |
| | 28,004 |
| | 16,099 |
|
Total identifiable assets | | $ | 1,140,510 |
| | $ | 1,067,421 |
| | $ | 1,346,750 |
| | $ | 1,229,219 |
|
Our operations are entirely domestic.
| |
8.7. | Accumulated Other Comprehensive LossStockholder's Equity |
Preferred Stock
We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of September 30, 2017 and December 31, 2016. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.
Common Stock Public Offering
In September 2016, we completed a public offering of 960,488 shares of our common stock at a public offering priceper share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 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.
Stockholders' Rights
Pursuant to authority granted under Delaware law and our Certificate of Incorporation, our Board of Directors previously declared a dividend of one preferred stock purchase right (each, a "Right," and, collectively, the "Rights") for each outstanding share of our common stock held of record on September 3, 1999, as adjusted for our stock split in September of 2014, and for additional shares of common stock issued since that time. The description and terms of the Rights are set forth in the Rights Plan. Unless exercised, the Rights trade with our common stock and are evidenced by the common stock certificate. In general, each Right will become exercisable and trade independently from our common stock upon a person or entity acquiring a beneficial ownership of 15 percent or more of our outstanding common stock.
Each Right, if it becomes exercisable, initially entitles the holder to purchase one fiftieth of a share of our Series A Participating Cumulative Preferred Stock, par value $0.01 per share, at a price of $70 per unit, subject to anti-dilution adjustments. Upon a person or entity becoming an "acquiring person," each Right (other than the Rights held by the acquiring person) will become exercisable to purchase a number of shares of our common stock having a market value equal to two times the exercise price of the Right. The Rights expire on August 20, 2019, unless they are redeemed earlier by us at the redemption price of $0.01 per Right. We may redeem the Rights at any time before they become exercisable and thereafter only in limited circumstances.
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 other comprehensive income (loss). loss.
The following tables present the changes in the balance of accumulated other comprehensive loss for the nine months ended September 30, 20162017 and 2015.2016. 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, 2016 | | $ | (5,360 | ) | | $ | 482 |
| | $ | (4,878 | ) |
Other comprehensive income/(loss) before reclassifications | | (9 | ) | | 322 |
| | 313 |
|
Amounts reclassified from accumulated other comprehensive income/(loss) | | 271 |
| | (965 | ) | | (694 | ) |
Net current-period other comprehensive income/(loss) | | 262 |
| | (643 | ) | | (381 | ) |
As of September 30, 2017 | | $ | (5,098 | ) | | $ | (161 | ) | | $ | (5,259 | ) |
|
| | | | | | | | | | | | |
| | 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 | ) |
|
| | | | | | | | | | | | |
| | 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 income before reclassifications | | — |
| | 641 |
| | 641 |
|
Amounts reclassified from accumulated other comprehensive income/(loss) | | 263 |
| | (93 | ) | | 170 |
|
Net prior-period other comprehensive income | | 263 |
| | 548 |
| | 811 |
|
As of September 30, 2016 | | $ | (5,317 | ) | | $ | 288 |
| | $ | (5,029 | ) |
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 20162017 and 2015.2016. 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.
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Amortization of defined benefit pension and postretirement plan items: | | | | | | | | | | | | | | | | |
Prior service cost (1) | | $ | 20 |
| | $ | 17 |
| | $ | 60 |
| | $ | 50 |
| |
Prior service credit (1) | | | $ | 19 |
| | $ | 20 |
| | $ | 58 |
| | $ | 60 |
|
Net loss (1) | | (166 | ) | | (155 | ) | | (500 | ) | | (465 | ) | | (171 | ) | | (166 | ) | | (509 | ) | | (500 | ) |
Total before income taxes | | (146 | ) |
| (138 | ) | | (440 | ) |
| (415 | ) | | (152 | ) |
| (146 | ) | | (451 | ) |
| (440 | ) |
Income tax benefit | | 58 |
| | 55 |
| | 177 |
| | 167 |
| | 61 |
| | 58 |
| | 180 |
| | 177 |
|
Net of tax | | $ | (88 | ) | | $ | (83 | ) | | $ | (263 | ) |
| $ | (248 | ) | | $ | (91 | ) | | $ | (88 | ) | | $ | (271 | ) |
| $ | (263 | ) |
| | | | | | | | | | | | | | | | |
Gains and losses on commodity contracts cash flow hedges | | | | | | | | | | | | | | | | |
Propane swap agreements (2) | | $ | — |
| | $ | — |
| | $ | (322 | ) | | $ | — |
| | $ | 198 |
| | $ | — |
| | $ | 663 |
| | $ | (322 | ) |
Call options (2) | | — |
| | — |
| | — |
| | (55 | ) | |
Natural gas swaps (2) | | | 1 |
| | — |
| | 1 |
| | — |
|
Natural gas futures (2) | | 105 |
| | — |
| | 464 |
| | — |
| | (852 | ) | | 105 |
| | 929 |
| | 464 |
|
Total before income taxes | | 105 |
| | — |
| | 142 |
|
| (55 | ) | | (653 | ) | | 105 |
| | 1,593 |
|
| 142 |
|
Income tax benefit (expense) | | (41 | ) | | — |
| | (49 | ) | | 22 |
| | 248 |
| | (41 | ) | | (628 | ) | | (49 | ) |
Net of tax | | 64 |
| | — |
|
| 93 |
| | (33 | ) | | (405 | ) | | 64 |
|
| 965 |
| | 93 |
|
Total reclassifications for the period | | $ | (24 | ) | | $ | (83 | ) |
| $ | (170 | ) | | $ | (281 | ) | | $ | (496 | ) | | $ | (24 | ) |
| $ | 694 |
| | $ | (170 | ) |
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 98, Employee Benefit Plans, for additional details.
(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12,11, 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 expenseincome (expense) in the accompanying condensed consolidated statements of income.
| |
9.8. | Employee Benefit Plans |
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 20162017 and 20152016 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 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan |
For the Three Months Ended September 30, | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | | | | | |
Interest cost | | $ | 103 |
| | $ | 105 |
| | $ | 623 |
| | $ | 635 |
| | $ | 22 |
| | $ | 23 |
| | $ | 11 |
| | $ | 11 |
| | $ | 13 |
| | $ | 14 |
|
Expected return on plan assets | | (127 | ) | | (131 | ) | | (699 | ) | | (625 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of prior service credit | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (19 | ) | | (20 | ) | | — |
| | — |
|
Amortization of net loss | | 107 |
| | 103 |
| | 131 |
| | 133 |
| | 22 |
| | 22 |
| | 17 |
| | 16 |
| | — |
| | — |
|
Net periodic cost (benefit) | | 83 |
| | 77 |
| | 55 |
| | 143 |
| | 44 |
| | 45 |
| | 9 |
| | 7 |
| | 13 |
| | 14 |
|
Amortization of pre-merger regulatory asset | | — |
| | — |
| | 191 |
| | 191 |
| | — |
| | — |
| | — |
| | — |
| | 2 |
| | 2 |
|
Total periodic cost | | $ | 83 |
| | $ | 77 |
| | $ | 246 |
| | $ | 334 |
| | $ | 44 |
| | $ | 45 |
| | $ | 9 |
| | $ | 7 |
|
| $ | 15 |
| | $ | 16 |
|
| | | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | 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 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | | | | |
Interest cost | | $ | 315 |
| | $ | 306 |
| | $ | 1,894 |
| | $ | 1,877 |
| | $ | 68 |
| | $ | 68 |
| | $ | 32 |
| | $ | 33 |
| | $ | 41 |
| | $ | 45 |
| | $ | 309 |
| | $ | 315 |
| | $ | 1,870 |
| | $ | 1,894 |
| | $ | 66 |
| | $ | 68 |
| | $ | 31 |
| | $ | 32 |
| | $ | 38 |
| | $ | 41 |
|
Expected return on plan assets | | (392 | ) | | (405 | ) | | (2,027 | ) | | (2,330 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (381 | ) | | (392 | ) | | (2,098 | ) | | (2,027 | ) | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
|
Amortization of prior service cost | | — |
| | — |
| | — |
| | — |
| | — |
| | 8 |
| | (60 | ) | | (58 | ) | | — |
| | — |
| |
Amortization of prior service credit | | | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | (58 | ) | | (60 | ) | | — |
| | — |
|
Amortization of net loss | | 309 |
| | 272 |
| | 389 |
| | 341 |
| | 66 |
| | 74 |
| | 51 |
| | 53 |
| | — |
| | 5 |
| | 319 |
| | 309 |
| | 392 |
| | 389 |
| | 65 |
| | 66 |
| | 50 |
| | 51 |
| | — |
| | — |
|
Net periodic cost (benefit) | | 232 |
| | 173 |
| | 256 |
| | (112 | ) | | 134 |
| | 150 |
| | 23 |
| | 28 |
| | 41 |
| | 50 |
| | 247 |
| | 232 |
| | 164 |
| | 256 |
| | 131 |
| | 134 |
| | 23 |
| | 23 |
| | 38 |
| | 41 |
|
Amortization of pre-merger regulatory asset | | — |
| | — |
| | 571 |
| | 571 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| | 6 |
| | — |
| | — |
| | 571 |
| | 571 |
| | — |
| | — |
| | — |
| | — |
| | 6 |
| | 6 |
|
Total periodic cost | | $ | 232 |
| | $ | 173 |
| | $ | 827 |
| | $ | 459 |
| | $ | 134 |
| | $ | 150 |
| | $ | 23 |
| | $ | 28 |
| | $ | 47 |
| | $ | 56 |
| | $ | 247 |
| | $ | 232 |
| | $ | 735 |
| | $ | 827 |
| | $ | 131 |
| | $ | 134 |
| | $ | 23 |
| | $ | 23 |
| | $ | 44 |
| | $ | 47 |
|
We expect to record pension and postretirement benefit costs of approximately $1.71.6 million for 2016.2017. Included in these costs is approximately $769,000$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$1.5 million and approximately $2.92.1 million at September 30, 20162017 and December 31, 20152016, 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 and nine months ended September 30, 20162017 and 2015:2016:
| | For the Three Months Ended September 30, 2016 | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total | |
For the Three Months Ended September 30, 2017 | | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total |
(in thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
Prior service credit | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (20 | ) | | $ | — |
| | $ | (20 | ) | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (19 | ) | | $ | — |
| | $ | (19 | ) |
Net loss | | 103 |
| | 133 |
| | 22 |
| | 16 |
| | — |
| | 274 |
| | 107 |
| | 131 |
| | 22 |
| | 17 |
| | — |
| | 277 |
|
Total recognized in net periodic benefit cost | | $ | 103 |
| | $ | 133 |
| | $ | 22 |
| | $ | (4 | ) | | $ | — |
| | $ | 254 |
| | 107 |
| | 131 |
| | 22 |
| | (2 | ) | | — |
| | 258 |
|
Recognized from accumulated other comprehensive loss (1) | | $ | 103 |
| | $ | 25 |
| | $ | 22 |
| | $ | (4 | ) | | $ | — |
| | $ | 146 |
| | 107 |
| | 25 |
| | 22 |
| | (2 | ) | | — |
| | 152 |
|
Recognized from regulatory asset | | — |
| | 108 |
| | — |
| | — |
| | — |
| | 108 |
| | — |
| | 106 |
| | — |
| | — |
| | — |
| | 106 |
|
Total | | $ | 103 |
| | $ | 133 |
| | $ | 22 |
| | $ | (4 | ) | | $ | — |
| | $ | 254 |
| | $ | 107 |
| | $ | 131 |
| | $ | 22 |
| | $ | (2 | ) | | $ | — |
| | $ | 258 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
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 |
|
Recognized from regulatory asset | | — |
| | 108 |
| | — |
| | — |
| | — |
| | 108 |
|
Total | | $ | 103 |
| | $ | 133 |
| | $ | 22 |
|
| $ | (4 | ) |
| $ | — |
|
| $ | 254 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
For the Nine Months Ended September 30, 2017 | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total |
(in thousands) | | | | | | | | | | | | |
Prior service credit | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (58 | ) | | $ | — |
| | $ | (58 | ) |
Net loss | | 319 |
| | 392 |
| | 65 |
| | 50 |
| | — |
| | 826 |
|
Total recognized in net periodic benefit cost | | 319 |
| | 392 |
| | 65 |
| | (8 | ) | | — |
| | 768 |
|
Recognized from accumulated other comprehensive loss (1) | | 319 |
| | 75 |
| | 65 |
| | (8 | ) | | — |
| | 451 |
|
Recognized from regulatory asset | | — |
| | 317 |
| | — |
| | — |
| | — |
| | 317 |
|
Total | | $ | 319 |
| | $ | 392 |
| | $ | 65 |
| | $ | (8 | ) | | $ | — |
| | $ | 768 |
|
| | For the Three Months Ended September 30, 2015 | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total | |
For the Nine Months Ended September 30, 2016 | | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total |
(in thousands) | | | | | | | | | | | | | | | | | | | | | | | | |
Prior service cost (credit) | | $ | — |
| | $ | — |
| | $ | 2 |
| | $ | (19 | ) | | $ | — |
| | $ | (17 | ) | |
Prior service credit | | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (60 | ) | | $ | — |
| | $ | (60 | ) |
Net loss | | 91 |
| | 114 |
| | 25 |
| | 17 |
| | 2 |
| | 249 |
| | 309 |
| | 389 |
| | 66 |
| | 51 |
| | — |
| | 815 |
|
Total recognized in net periodic benefit cost | | $ | 91 |
| | $ | 114 |
| | $ | 27 |
| | $ | (2 | ) | | $ | 2 |
| | $ | 232 |
| | 309 |
| | 389 |
| | 66 |
| | (9 | ) | | — |
| | 755 |
|
Recognized from accumulated other comprehensive loss (1) | | $ | 91 |
| | $ | 22 |
| | $ | 27 |
| | $ | (2 | ) | | $ | — |
| | $ | 138 |
| | 309 |
| | 74 |
| | 66 |
| | (9 | ) | | — |
| | 440 |
|
Recognized from regulatory asset | | — |
| | 92 |
| | — |
| | — |
| | 2 |
| | 94 |
| | — |
| | 315 |
| | — |
| | — |
| | — |
| | 315 |
|
Total | | $ | 91 |
| | $ | 114 |
| | $ | 27 |
|
| $ | (2 | ) |
| $ | 2 |
|
| $ | 232 |
| | $ | 309 |
| | $ | 389 |
| | $ | 66 |
| | $ | (9 | ) | | $ | — |
| | $ | 755 |
|
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 nine months ended September 30, 2016 and 2015:
|
| | | | | | | | | | | | | | | | | | | | | | | | |
For the Nine 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 | | $ | — |
| | $ | — |
| | $ | — |
| | $ | (60 | ) | | $ | — |
| | $ | (60 | ) |
Net loss | | 309 |
| | 389 |
| | 66 |
| | 51 |
| | — |
| | $ | 815 |
|
Total recognized in net periodic benefit cost | | $ | 309 |
| | $ | 389 |
|
| $ | 66 |
|
| $ | (9 | ) |
| $ | — |
|
| $ | 755 |
|
Recognized from accumulated other comprehensive loss (1) | | $ | 309 |
| | $ | 74 |
| | $ | 66 |
| | $ | (9 | ) | | $ | — |
| | $ | 440 |
|
Recognized from regulatory asset | | — |
| | 315 |
| | — |
| | — |
| | — |
| | 315 |
|
Total | | $ | 309 |
| | $ | 389 |
| | $ | 66 |
| | $ | (9 | ) | | $ | — |
| | $ | 755 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | |
For the Nine Months Ended September 30, 2015 | | Chesapeake Pension Plan | | FPU Pension Plan | | Chesapeake SERP | | Chesapeake Postretirement Plan | | FPU Medical Plan | | Total |
(in thousands) | | | | | | | | | | | | |
Prior service cost (credit) | | $ | — |
| | $ | — |
| | $ | 8 |
| | $ | (58 | ) | | $ | — |
| | $ | (50 | ) |
Net loss | | 272 |
| | 341 |
| | 74 |
| | 53 |
| | 5 |
| | 745 |
|
Total recognized in net periodic benefit cost | | $ | 272 |
| | $ | 341 |
| | $ | 82 |
| | $ | (5 | ) | | $ | 5 |
| | $ | 695 |
|
Recognized from accumulated other comprehensive loss (1) | | $ | 272 |
| | $ | 65 |
| | $ | 82 |
| | $ | (5 | ) | | $ | 1 |
| | $ | 415 |
|
Recognized from regulatory asset | | — |
| | 276 |
| | — |
| | — |
| | 4 |
| | 280 |
|
Total | | $ | 272 |
| | $ | 341 |
| | $ | 82 |
| | $ | (5 | ) | | $ | 5 |
| | $ | 695 |
|
| |
(1)
| See Note 8, Accumulated Other Comprehensive Loss(1) See Note 7, Stockholder's Equity.
|
During the three and nine months ended September 30, 2016,2017, we contributed approximately $116,000$67,000 and $390,000,$234,000, respectively, to the Chesapeake Pension Plan and approximately $374,000$110,000 and approximately $1.3$1.6 million, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $508,000$746,000 and approximately $1.6$3.0 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2016,2017, which representrepresents the minimum annual contribution payments required.
The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and nine months ended September 30, 2016,2017, were approximately $38,000 and approximately $114,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2016.2017. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2016,2017, were approximately $23,000$30,000 and approximately $59,000,$94,000, respectively. We estimate that approximately $82,000$83,000 will be paid
for such benefits under the Chesapeake Postretirement Plan in 2016.2017. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2016,2017, were approximately $32,000$13,000 and approximately $97,000,$48,000, respectively. We estimate that approximately $149,000$129,000 will be paid for such benefits under the FPU Medical Plan in 2016.2017.
The investment balances at September 30, 20162017 and December 31, 2015,2016, consisted of the following:
| | | | | | | | |
(in thousands) | September 30, 2016 | | December 31, 2015 | September 30, 2017 | | December 31, 2016 |
Rabbi trust (associated with the Deferred Compensation Plan) | $ | 4,609 |
| | $ | 3,626 |
| $ | 6,358 |
| | $ | 4,881 |
|
Investments in equity securities | 21 |
| | 18 |
| 22 |
| | 21 |
|
Total | $ | 4,630 |
| | 3,644 |
| $ | 6,380 |
| | 4,902 |
|
We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 20162017 and 2015,2016, we recorded a net unrealized gain of approximately $193,000$261,000 and $238,000,$193,000, respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 20162017 and 2015,2016, we recorded an unrealized gain of approximately $246,000$694,000 and a net unrealized loss of approximately $131,000,$246,000, respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the investments in the Rabbi Trust.
| |
11.10. | Share-Based Compensation |
Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares
awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.
The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months ended September 30, 20162017 and 2015:2016:
| | | | Three Months Ended | | Nine Months Ended | | Three Months Ended | | Nine Months Ended |
| | September 30, | | September 30, | | September 30, | | September 30, |
| | 2016 | | 2015 | | 2016 | | 2015 | | 2017 | | 2016 | | 2017 | | 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Awards to non-employee directors | | $ | 135 |
| | $ | 165 |
| | $ | 445 |
| | $ | 475 |
| | $ | 134 |
| | $ | 135 |
| | $ | 406 |
| | $ | 445 |
|
Awards to key employees | | 488 |
| | 334 |
| | 1,442 |
| | 970 |
| | 662 |
| | 488 |
| | 1,202 |
| | 1,442 |
|
Total compensation expense | | 623 |
| | 499 |
| | 1,887 |
| | 1,445 |
| | 796 |
| | 623 |
| | 1,608 |
| | 1,887 |
|
Less: tax benefit | | (251 | ) | | (201 | ) | | (760 | ) | | (582 | ) | | (320 | ) | | (251 | ) | | (647 | ) | | (760 | ) |
Share-based compensation amounts included in net income | | $ | 372 |
| | $ | 298 |
| | $ | 1,127 |
| | $ | 863 |
| | $ | 476 |
| | $ | 372 |
| | $ | 961 |
| | $ | 1,127 |
|
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 grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2016,2017, each of our non-employee directors received an annual retainer of 953835 shares of common stock under the SICP for service as a director through the 20172018 Annual Meeting of Stockholders.
A summary of the stock activity for our non-employee directors during the nine months ended September 30, 20162017 is presented below:
| | | | Number of Shares | | Weighted Average Fair Value | | Number of Shares | | Weighted Average Fair Value |
Outstanding— December 31, 2015 | | — |
| | $ | — |
| |
Outstanding— December 31, 2016 | | | — |
| | $ | — |
|
Granted | | 8,577 |
| | $ | 62.90 |
| | 7,515 |
| | $ | 71.80 |
|
Vested | | (8,577 | ) | | $ | 62.90 |
| | (7,515 | ) | | $ | 71.80 |
|
Outstanding— September 30, 2016 | | — |
| | $ | — |
| |
Outstanding— September 30, 2017 | | | — |
| | $ | — |
|
At September 30, 2016,2017, there was approximately $314,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periodperiods ending April 30, 2017.
2018.
Key Employees
The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, 2016:2017:
| | | | Number of Shares | | Weighted Average Fair Value | | Number of Shares | | Weighted Average Fair Value |
Outstanding— December 31, 2015 | | 110,398 |
| | $ | 38.34 |
| |
Outstanding— December 31, 2016 | | | 115,091 |
| | $ | 51.85 |
|
Granted | | 46,571 |
| | $ | 67.90 |
| | 52,355 |
| | $ | 63.42 |
|
Vested | | (39,553 | ) | | $ | 31.79 |
| | (32,926 | ) | | $ | 38.88 |
|
Expired | | (2,325 | ) | | $ | 42.25 |
| | (1,878 | ) | | $ | 39.97 |
|
Outstanding— September 30, 2016 | | 115,091 |
| | $ | 52.36 |
| |
Outstanding— September 30, 2017 | | | 132,642 |
| | $ | 52.42 |
|
In February 2016,and May 2017, our Board of Directors granted awards of 46,57152,355 shares of common stock to key employees under the SICP. The shares granted in February 2016and May 2017 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2018.2019. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.
At the election of certain of our executives, in March 2017, for shares that were awarded for the performance period ending December 31, 2016, we withheld shares with a value at least equivalent to each such executive’s minimum statutory obligation for applicable income and other employment taxes, remitted the cash to the appropriate taxing authorities, and paid the balance of such shares to each such executive. We withheld 10,269 shares, based on the value of the shares on their award date, determined by the average of the high and low prices of our common stock. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $692,000.
At September 30, 2016,2017, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $7.0$10.4 million. At September 30, 2016,2017, there was approximately $2.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2017 through 2019.
Stock Options
We did not have any stock options outstanding at September 30, 2017 or 2016, through 2018.nor were any stock options issued during these periods.
| |
12.11. | 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. WeOur natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of September 30, 2016,2017, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Hedging Activities in 2017
In 2017, Sharp entered into several swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 11.1 million gallons expected to be purchased from October 2017 through September 2018. Under the swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through September 2018) and the swap prices of $0.5900 and $0.6750 per gallon, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap price, Sharp will pay the difference. We accounted for these swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At September 30, 2017, the swap agreements had a fair value asset of approximately $1.5 million. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).
PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts have a two-year term, and we accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2017, PESCO had a total of 4.0 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $1.3 million accounted for as a cash flow hedge. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).
In August 2017, PESCO entered into natural gas swap agreements associated with ARM's financial contracts to mitigate the risk of fluctuations in wholesale natural gas prices associated with 12.0 million Dts PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, with a liability fair value of approximately $412,000. The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).
The impact of PESCO's financial instruments that were not designated as hedges in our condensed consolidated financial statements for the nine months ended September 30, 2017 was $13,000, which was recorded as an increase in gas costs and is associated with 1.4 million Dts of natural gas. This presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments.
Hedging Activities in 2016
In 2016, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 4.14.8 million gallons expected to be purchased for the upcoming heating season.through September 2017. Under the swap agreements, Sharp willwould receive the difference between the index prices (Mont Belvieu prices in DecemberOctober 2016 through September 2017) and the swap prices of $0.5250$0.5225 and $0.5525$0.5650 per gallon, to the extent the index prices exceedexceeded the swap prices. If the index prices arewere lower than the swap price, Sharp willwould pay the difference. TheSharp received a total of approximately $193,000, which represented the difference between the index prices and swap agreement essentially fixesprices during the pricemonths of the 4.1 million gallons that we expect to purchase for the upcoming heating season.October 2016 through September 2017. We had accounted for these swap
agreements as cash flow hedges,hedges.
In December 2016, Sharp paid a total of $33,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons for its propane price cap program in the 2016-2017 heating season. The put option expired without being exercised because the propane prices did not fall below the strike price of $0.5650 per gallon in December 2016, January 2017, or February 2017. We accounted for the put option as a fair value hedge, and there iswas no ineffective portion of these hedges. At September 30, 2016, the swap agreements had a fair value of approximately $237,000. The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).
this hedge.
In January 2016, PESCO entered into a SCO supplier agreement with Columbia Gas to provide natural gas supply for Columbia Gas to service one of its local distribution customer tranches.pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, which terminatesterminated on March 31, 2017.
In conjunction with the SCO supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. The contracts expire within one year. We had previously accounted for these contracts as fair value hedges, with any ineffective portion being reported directly in earnings and offset by any associated gain (loss) on the inventory value being hedged. During the third quarter of 2016, we de-designateddiscontinued hedge accounting as the hedges as they were no longer highly effective. We are now accounting for them as derivatives on a mark-to-market basis with the change in fair value reflected as unrealized gain (loss) in current period earnings, and these are no longer offset by any associated gain (loss) in the value of the inventory previously hedged. As of September 30, 2016, we had a total of 1.8 million Dts/d in natural gas futures2017, these contracts with a mark-to-market liability of $29,000.have all expired and are no longer reported on the balance sheet.
Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts expire within two years, and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2016, PESCO had a total of 6.0 million Dts/d hedged under natural gas futures contracts, with an asset fair value of approximately $240,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).
Fair Value Hedges
The impact of our natural gas futures commodity contracts previously designated as fair value hedges and the related hedged item on our condensed consolidated income statements for the three and nine months ended September 30, 2016 is presented below:
|
| | | | | | | | | |
| | | Three Months Ended | | Nine Months Ended |
(in thousands) | | | September 30, 2016 (1) | | September 30, 2016 (1) |
Commodity contracts | | $ | — |
| | $ | (233 | ) |
Fair value adjustment for natural gas inventory designated as the hedged item | | — |
| | 681 |
|
Total increase in purchased gas cost | | $ | — |
| | $ | 448 |
|
| | | | | |
The increase in purchased gas cost is comprised of the following: | | | | |
Basis ineffectiveness | | $ | — |
| | $ | (83 | ) |
Timing ineffectiveness | | — |
| | 531 |
|
Total ineffectiveness | | $ | — |
| | $ | 448 |
|
| |
(1)
| There were no natural gas futures commodity contracts designated as fair value hedges in 2015. |
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedging instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that our natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.
Hedging Activities in 2015
In March, May and June 2015, Sharp paid a total of approximately $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the 2015-2016 heating season. We exercised the put options as propane prices fell below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. We received approximately $239,000, which represents the difference between the market prices
and the strike prices during those months. We accounted for the put options as fair value hedges.
In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 per gallon, for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid approximately $484,000, which represents the difference between the index prices and swap prices during those months of the swap agreements.
Commodity Contracts for Trading Activities
Shortly after the first quarter of 2017, Xeron engageswound down its operations. Xeron was previously engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts arewere considered derivatives and have beenwere 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 statements of income for the period of change. As of September 30, 2016,2017, Xeron had no outstanding contracts that were accounted for as derivatives.
Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At September 30, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable 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-relatedcredit risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 20162017 and December 31, 2015,2016, are as follows:
| | | | Asset Derivatives | |
|
| | | | Fair Value As Of | | | | Fair Value As Of |
(in thousands) | | Balance Sheet Location | | September 30, 2016 | | December 31, 2015 | | Balance Sheet Location | | September 30, 2017 | | December 31, 2016 |
Derivatives not designated as hedging instruments | | | | | | | | |
Forward & Future contracts | | Mark-to-market energy assets | | $ | — |
| | $ | 1 |
| |
Derivatives designated as fair value hedges | | | | | |
Propane swap agreements | | | Derivative assets, at fair value | | $ | 15 |
| | $ | 8 |
|
Put options | | Mark-to-market energy assets | | — |
| | 152 |
| | Derivative assets, at fair value | | — |
| | 9 |
|
Natural gas swap contracts | | | Derivative assets, at fair value | | 1 |
| | — |
|
Derivatives designated as cash flow hedges | | | | | | | | |
Natural gas futures contracts | | Mark-to-market energy assets | | 240 |
| | — |
| | Derivative assets, at fair value | | — |
| | 113 |
|
Propane swap agreements | | Mark-to-market energy assets | | 237 |
| | — |
| | Derivative assets, at fair value | | 1,510 |
| | 693 |
|
Total asset derivatives | | $ | 477 |
| | $ | 153 |
| | $ | 1,526 |
| | $ | 823 |
|
| | | | Liability Derivatives | | Liability Derivatives |
| | | | Fair Value As Of | | | | Fair Value As Of |
(in thousands) | | Balance Sheet Location | | September 30, 2016 | | December 31, 2015 | | Balance Sheet Location | | September 30, 2017 | | December 31, 2016 |
Derivatives not designated as hedging instruments | | | | | | | | |
Forward contracts | | Mark-to-market energy liabilities | | $ | — |
| | $ | 1 |
| |
Natural gas futures contracts | | Mark-to-market energy liabilities | | 29 |
| | — |
| |
Derivatives designated as fair value hedges | | | | | |
Natural gas futures contracts | | Mark-to-market energy liabilities | | — |
| | — |
| | Derivative liabilities, at fair value | | $ | 13 |
| | $773 |
Derivatives designated as cash flow hedges | | | | | | | | |
Propane swap agreements | | Mark-to-market energy liabilities | | — |
| | 323 |
| |
Natural gas swap contracts | | | Derivative liabilities, at fair value | | 412 |
| | — |
|
Natural gas futures contracts | | Mark-to-market energy liabilities | | — |
| | 109 |
| | Derivative liabilities, at fair value | | 1,307 |
| | — |
|
Total liability derivatives | | $ | 29 |
| | $ | 433 |
| | $ | 1,732 |
| | $ | 773 |
|
The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:
| | | | | | Amount of Gain (Loss) on Derivatives: | | | | Amount of Gain (Loss) on Derivatives: |
| | Location of Gain | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, | | Location of Gain | | For the Three Months Ended September 30, | | For the Nine Months Ended September 30, |
(in thousands) | | (Loss) on Derivatives | | 2016 | | 2015 | | 2016 | | 2015 | | (Loss) on Derivatives | | 2017 | | 2016 | | 2017 | | 2016 |
Derivatives not designated as hedging instruments | | | | | | | | | | | | | | | | | | | | |
Realized gain (loss) on forward contracts (1) | | Revenue | | $ | (231 | ) | | $ | 187 |
| | $ | 44 |
| | $ | 393 |
| |
Realized gain on forward contracts and options (1) | | | Revenue | | $ | — |
| | $ | (231 | ) | | $ | 112 |
| | $ | 44 |
|
Unrealized gain (loss) on forward contracts (1) | | Revenue | | (2 | ) | | (7 | ) | | — |
| | 71 |
| | Revenue | | — |
| | (2 | ) | | — |
| | — |
|
Natural gas futures contracts | | Cost of sales | | 205 |
| | — |
| | 205 |
| | — |
| | Cost of sales | | 286 |
| | 205 |
| | 907 |
| | 205 |
|
Propane swap agreements | | Cost of sales | | — |
| | — |
| | — |
| | 18 |
| | Cost of sales | | 15 |
| | — |
| | 11 |
| | — |
|
Natural gas swap contracts | | | Cost of sales | | 1 |
| | — |
| | 1 |
| | — |
|
Derivatives designated as fair value hedges | | | | | | | | | | | | | | | | |
Put /Call options | | Cost of sales | | — |
| | — |
| | 73 |
| | 506 |
| |
Put /Call options (2) | | Propane Inventory | | — |
| | (46 | ) | | — |
| | (79 | ) | |
Put /Call option (2) | | | Cost of sales | | — |
| | — |
| | (9 | ) | | 73 |
|
Natural gas futures contracts | | Natural Gas Inventory | | — |
| | — |
| | (233 | ) | | — |
| | Natural gas inventory | | — |
| | — |
| | — |
| | (233 | ) |
Derivatives designated as cash flow hedges | | | | | | | | | | | | | | | | |
Propane swap agreements | | Cost of sales | | — |
| | — |
| | (364 | ) | | — |
| | Cost of sales | | 198 |
| | — |
| | 663 |
| | (364 | ) |
Propane swap agreements | | Other Comprehensive Gain (Loss) | | 213 |
| | (126 | ) | | 559 |
| | (128 | ) | | Other comprehensive income | | 1,590 |
| | 213 |
| | 814 |
| | 559 |
|
Call options | | Cost of sales | | — |
| | — |
| | — |
| | (81 | ) | |
Natural gas futures contracts | | Cost of sales | | 105 |
| | — |
| | 464 |
| | — |
| | Cost of sales | | (852 | ) | | 105 |
| | 929 |
| | 464 |
|
Natural gas futures contracts | | Other Comprehensive Gain (Loss) | | (123 | ) | | — |
| | 349 |
| | — |
| | Other comprehensive income (loss) | | (1,296 | ) | | (123 | ) | | (1,420 | ) | | 349 |
|
Natural gas swap agreements | | | Cost of sales | | 1 |
| | — |
| | 1 |
| | — |
|
Natural gas swap agreements | | | Other comprehensive loss | | (413 | ) | | — |
| | (413 | ) | | — |
|
Total | | $ | 167 |
| | $ | 8 |
| | $ | 1,097 |
| | $ | 700 |
| | $ | (470 | ) | | $ | 167 |
| | $ | 1,596 |
| | $ | 1,097 |
|
| |
(1) | All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. |
| |
(2) | As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory.inventory on the condensed consolidated balance sheets. |
| |
13.12. | Fair Value of Financial Instruments |
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
Financial Assets and Liabilities Measured at Fair Value
The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of September 30, 20162017 and December 31, 2015:2016:
| | | | | | Fair Value Measurements Using: | | | | Fair Value Measurements Using: |
As of September 30, 2016 | | Fair Value | | Quoted- Prices- in Active Markets (Level 1) | | Significant- Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
As of September 30, 2017 | | | Fair Value | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
(in thousands) | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Investments—equity securities | | $ | 21 |
| | $ | 21 |
| | $ | — |
| | $ | — |
| | $ | 22 |
| | $ | 22 |
| | $ | — |
| | $ | — |
|
Investments—guaranteed income fund | | $ | 485 |
| | $ | — |
| | $ | — |
| | $ | 485 |
| | 642 |
| | — |
| | — |
| | 642 |
|
Investments—mutual funds and other | | $ | 4,124 |
| | $ | 4,124 |
| | $ | — |
| | $ | — |
| | 5,716 |
| | 5,716 |
| | — |
| | — |
|
Mark-to-market energy assets, incl. put options and swap agreements | | $ | 477 |
| | $ | — |
| | $ | 477 |
| | $ | — |
| |
Total investments | | | 6,380 |
| | 5,738 |
|
| — |
|
| 642 |
|
Derivative assets | | | 1,526 |
| | — |
| | 1,526 |
| | — |
|
Total assets | | | $ | 7,906 |
|
| $ | 5,738 |
|
| $ | 1,526 |
|
| $ | 642 |
|
Liabilities: | | | | | | | | | | | | | | | | |
Mark-to-market energy liabilities incl. swap agreements | | $ | 29 |
| | $ | — |
| | $ | 29 |
| | $ | — |
| |
Derivative liabilities | | | $ | 1,732 |
| | $ | — |
| | $ | 1,732 |
| | $ | — |
|
| | | | | | Fair Value Measurements Using: | | | | Fair Value Measurements Using: |
As of December 31, 2015 | | Fair Value | | Quoted- Prices- in Active Markets (Level 1) | | Significant- Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) | |
As of December 31, 2016 | | | Fair Value | | Quoted Prices in Active Markets (Level 1) | | Significant Other Observable Inputs (Level 2) | | Significant Unobservable Inputs (Level 3) |
(in thousands) | | | | | | | | | | | | | | | | |
Assets: | | | | | | | | | | | | | | | | |
Investments—equity securities | | $ | 18 |
| | $ | 18 |
| | $ | — |
| | $ | — |
| | $ | 21 |
| | $ | 21 |
| | $ | — |
| | $ | — |
|
Investments—guaranteed income fund | | $ | 279 |
| | $ | — |
| | $ | — |
| | $ | 279 |
| | 561 |
| | — |
| | — |
| | 561 |
|
Investments—mutual funds and other | | $ | 3,347 |
| | $ | 3,347 |
| | $ | — |
| | $ | — |
| | 4,320 |
| | 4,320 |
| | — |
| | — |
|
Mark-to-market energy assets, incl. put/call options | | $ | 153 |
| | $ | — |
| | $ | 153 |
| | $ | — |
| |
Total investments | | | 4,902 |
| | 4,341 |
|
| — |
|
| 561 |
|
Derivative assets | | | 823 |
| | — |
| | 823 |
| | — |
|
Total assets | | | $ | 5,725 |
|
| $ | 4,341 |
|
| $ | 823 |
|
| $ | 561 |
|
Liabilities: | | | | | | | | | | | | | | | | |
Mark-to-market energy liabilities, incl. swap agreements | | $ | 433 |
| | $ | — |
| | $ | 433 |
| | $ | — |
| |
Derivative liabilities | | | $ | 773 |
| | $ | — |
| | $ | 773 |
| | $ | — |
|
The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above on a recurring basis as of September 30, 2016 and December 31, 2015:above:
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 - mutual funds and 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 energyDerivative assets and liabilities — TheseThe fair values of forward contracts are valuedmeasured using market transactions in either the listed or OTC markets.
Propane put/call options, swap agreements and natural gas futures contracts – The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.
Level 3 Fair Value Measurements:
Investments-Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value.
The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 20162017 and 2015:2016:
| | | Nine Months Ended September 30, | Nine Months Ended September 30, |
| 2016 | | 2015 | 2017 | | 2016 |
(in thousands) | | | | | | |
Beginning Balance | $ | 279 |
| | $ | 287 |
| $ | 561 |
| | $ | 279 |
|
Purchases and adjustments | 120 |
| | (11 | ) | 76 |
| | 120 |
|
Transfers | 88 |
| | (3 | ) | — |
| | 88 |
|
Distribution | (8 | ) | | — |
| (2 | ) | | (8 | ) |
Investment income | 6 |
| | 3 |
| 7 |
| | 6 |
|
Ending Balance | $ | 485 |
| | $ | 276 |
| $ | 642 |
| | $ | 485 |
|
Investment income from the Level 3 investments is reflected in other income (expense)expense, (net) in the accompanying condensed consolidated statements of income.
At September 30, 2016,2017, 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 September 30, 20162017, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $151.8$211.4 million. This compares to a fair value of approximately $173.5$224.2 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2015,2016, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $153.7$145.9 million, compared to the estimated fair value of approximately $165.1$161.5 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.
Our outstanding long-term debt is shown below:
| | | | September 30, | | December 31, | | September 30, | | December 31, |
(in thousands) | | 2016 | | 2015 | | 2017 | | 2016 |
FPU secured first mortgage bonds (1) : | | | | | | | | |
9.08% bond, due June 1, 2022 | | $ | 7,976 |
| | $ | 7,973 |
| | $ | 7,981 |
| | $ | 7,978 |
|
Uncollateralized senior notes: | | | | | | | | |
6.64% note, due October 31, 2017 | | 5,455 |
| | 5,455 |
| | 2,727 |
| | 2,727 |
|
5.50% note, due October 12, 2020 | | 10,000 |
| | 10,000 |
| | 8,000 |
| | 8,000 |
|
5.93% note, due October 31, 2023 | | 22,500 |
| | 24,000 |
| | 19,500 |
| | 21,000 |
|
5.68% note, due June 30, 2026 | | 29,000 |
| | 29,000 |
| | 26,100 |
| | 29,000 |
|
6.43% note, due May 2, 2028 | | 7,000 |
| | 7,000 |
| | 7,000 |
| | 7,000 |
|
3.73% note, due December 16, 2028 | | 20,000 |
| | 20,000 |
| | 20,000 |
| | 20,000 |
|
3.88% note, due May 15, 2029 | | 50,000 |
| | 50,000 |
| | 50,000 |
| | 50,000 |
|
3.25% note, due April 30, 2032 | | | 70,000 |
| | — |
|
Promissory notes | | 168 |
| | 238 |
| | 97 |
| | 168 |
|
Capital lease obligation | | 3,814 |
| | 4,824 |
| | 2,425 |
| | 3,471 |
|
Less: debt issuance costs | | | (446 | ) | | (291 | ) |
Total long-term debt | | 155,913 |
| | 158,490 |
| | 213,384 |
| | 149,053 |
|
Less: current maturities | | (12,087 | ) | | (9,151 | ) | | (12,136 | ) | | (12,099 | ) |
Less: debt issuance costs | | (301 | ) | | (333 | ) | |
Total long-term debt, net of current maturities | | $ | 143,525 |
| | $ | 149,006 |
| | $ | 201,248 |
|
| $ | 136,954 |
|
(1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.
Shelf AgreementAgreements
OnIn October 8, 2015, we entered into athe Prudential Shelf Agreement, with Prudential. Under the terms of the Shelf Agreement, through October 8, 2018,under which we may request that Prudential purchase, through October 8, 2018, up to $150.0 million of ourPrudential Shelf Notes. The Prudential Shelf Notes athave a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness
In May 2016, Prudential confirmed and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase.
On May 13, 2016, we submitted aaccepted our request that Prudential purchase $70.0 million of 3.25 percent Prudential Shelf Notes, under the Shelf Agreement. On May 20, 2016, Prudential accepted and confirmed our request.which were issued on April 21, 2017. The proceeds received from the issuancesthis issuance of thePrudential Shelf Notes will bewere used to reduce short-term borrowings under the Company’s revolving credit facility, lines of credit and/or to fundRevolver. The balance under the Revolver had accumulated over time as capital expenditures. The closing of the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.expenditures were temporarily financed.
The Prudential Shelf Agreement sets forth certain business covenants to which we are subject when any Prudential Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.
On October 8, 2015,In March 2017, we entered into the CreditMetLife Shelf Agreement withand the Lenders for aNYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million Revolver forand $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a termfixed interest rate and a maturity date not to exceed 20 years from the date of five years, subjectissuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the terms and conditionstime of the Credit Agreement. Borrowingspurchase. As of September 30, 2017, no unsecured senior debt has been issued under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirementsMetLife and capital expenditures.NYL Shelf Agreements.
Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders
to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. At September 30, 2016 and December 31, 2015, we had outstanding borrowings of $50.0 million and $35.0 million, respectively, under the Revolver.
The net proceeds from the sale of our common stock on September 22, 2016, of approximately $57.3 million, after deducting underwriting commissions and expenses, were added to our general funds and used to repay a portion of our short-term debt under unsecured lines of credit.
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, 2015,2016, 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. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future event or otherwise. These statements are subject to many risks uncertainties and otheruncertainties. In addition to the risk factors described under Item 1A, Risk Factors in our 2016 Annual Report on Form 10-K, the following important factors, thatamong others, could cause actual future results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:statements:
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 the degree to, whichof competition entersentering 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 recoverable in rates;
the timing of certificate authorizations associated with new capital projects;
changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now or may in the future own or operate;
possible increased federal, state and local regulation of the safety of our operations;
general economic conditions, including any potential effects arising from terrorist attacks and any hostilities or other external factors over which we have no control;
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;
industrial, commercial and residential growth or contraction in our markets or service territories;
the timing and extent of changes in commodity prices and interest rates;
the ability to establish and maintain key supply sources;
the effect of spot, forward and future market prices on our various energy businesses;
the effect of competition on our businesses;
the capital-intensive nature of our regulated energy businesses;
the extent of our success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;
the ability to construct facilities at or below estimated costs and within projected time frames;
the creditworthiness of counterparties with which we are engaged in transactions;
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 ability to establish and maintain new key supply sources;
changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now or may in the future own or operate;
general economic conditions, including any potential effects arising from terrorist attacks and any hostilities or other external factors over which we have no control;
conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;
the ability to continue to hire, train and retain appropriately qualified personnel;
the creditworthiness of counterparties with which we are engaged in transactions;
the effect of spot, forward and future market prices on our various energy businesses;
the ability to construct facilities at or below estimated costs;
possible increased federal, state and local regulation of the safety of our operations;
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 inherent hazards and risks involved in our energy businesses;
risks related to cyber-attacks that could disrupt our business operations or result in failure of information technology systems.
the effect of competition on our businesses;
the impact on our cost and funding obligations under our pension and other post-retirement benefit plans of potential downturns in the financial markets, lower discount rates, and costs associated with the Patient Protection and Affordable Care Act;
the ability to continue to hire, train and retain appropriately qualified personnel;
the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;
the timing and success of regulatorytechnological improvements;
risks related to cyber-attacks that could disrupt our business operations or result in failure of information technology systems;
the impact of significant changes to current tax regulations and other governmental approvals, authorizations, and permits;rates; and
the impact of future rate case proceedings.
Introduction
We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in variousregulated and unregulated energy and other businesses.
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. We are focused on identifying and developing opportunities across the energy value chain, with emphasis on midstream and downstream investments that are accretive to earnings per share and consistent with our long-term growth strategy.
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 regulatedour energy distribution and transmission businesses organically as well as into new geographic areas and areas;
providing new services in our current service territories;
expanding the propane distribution businessour footprint in existing and newpotential growth markets through leveraging our community gas system services, our vehicular fuel offerings and our bulk delivery capabilities;
expanding both our regulated 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 operating units and growth strategy while capitalizing on opportunities across the energy value chain; 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 customersdifferentiating the Company as a full-service energy supplier/partner/provider 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;
continuing to build a branded culture that drives a shared mission, vision, and values;
maintaining a consistent and competitive dividend for stockholders; and
creating and maintaining a diversified customer base, energy portfolio and utility foundation.customer-centric model.
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 documentthis Quarterly Report on Form 10-Q on operating income and segment results include the use of the term “gross margin.” “Gross margin”margin", which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased fuel cost forof natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities.activities, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. Chesapeake Utilities believesWe believe that gross margin, although a non-GAAP measure, is useful and meaningful in our regulated operations because the cost of natural gas and electricity are passed through to customers and changes in commodity prices can cause revenue to go up and down in ways that are not indicative of volumes sold or tied to profitability. Gross margininvestors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by Chesapeake Utilitiesus under itsour allowed rates for regulated operations and under itsour competitive pricing structure for non-regulated segments. Chesapeake Utilities'Our management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.
Unless otherwise noted, earnings per share information is presented on a diluted basis.
Results of Operations for the Three and Nine Months ended September 30, 20162017
Overview
Chesapeake Utilities Corporation is a Delaware corporation formed in 1947. We are a diversified energy company engaged, through our operating divisions and subsidiaries, in regulated energy, unregulated energy and other businesses. We operate primarily on the Delmarva Peninsula and in Florida, Pennsylvania and Ohio and provide natural gas distribution, transmission, supply, gathering, processing and marketing; electric distribution and generation; propane distribution; steam generation; and other energy-related services.
Operational Highlights
Our net income for the quarter ended September 30, 20162017 was $6.8 million, or $0.42 per share. This represents an increase of $2.4 million, or $0.13 per share, compared to net income of $4.4 million, or $0.29 per share, reported for the same quarter in 2016. Operating income increased $4.1 million for the three months ended September 30, 2017.
|
| | | | | | | | | | | | |
| | Three Months Ended | | |
| | September 30, | | Increase |
| | 2017 | | 2016 | | (decrease) |
(in thousands except per share) | | | | | | |
Business Segment: | | | | | | |
Regulated Energy segment | | $ | 15,168 |
| | $ | 13,115 |
| | $ | 2,053 |
|
Unregulated Energy segment | | (989 | ) | | (3,080 | ) | | 2,091 |
|
Other businesses and eliminations | | 60 |
| | 121 |
| | (61 | ) |
Operating Income | | $ | 14,239 |
| | $ | 10,156 |
| | $ | 4,083 |
|
Other income (expense), net | | 239 |
| | (28 | ) | | 267 |
|
Interest charges | | 3,321 |
| | 2,722 |
| | 599 |
|
Pre-tax Income | | 11,157 |
| | 7,406 |
| | 3,751 |
|
Income taxes | | 4,324 |
| | 2,990 |
| | 1,334 |
|
Net Income | | $ | 6,833 |
| | $ | 4,416 |
| | $ | 2,417 |
|
Earnings Per Share of Common Stock | | | | | | |
Basic | | $ | 0.42 |
| | $ | 0.29 |
| | $ | 0.13 |
|
Diluted | | $ | 0.42 |
| | $ | 0.29 |
| | $ | 0.13 |
|
Key variances, between the third quarter of 2017 and the third quarter of 2016, included:
|
| | | | | | | | | | | | |
(in thousands, except per share data) | | Pre-tax Income | | Net Income | | Earnings Per Share |
Third Quarter of 2016 Reported Results | | $ | 7,406 |
| | $ | 4,416 |
| | $ | 0.29 |
|
| | | | | | |
Adjusting for unusual items: | | | | | | |
Absence of Xeron's third quarter 2016 loss | | 545 |
| | 334 |
| | 0.02 |
|
Weather impact | | (333 | ) | | (204 | ) | | (0.01 | ) |
| | 212 |
|
| 130 |
|
| 0.01 |
|
Increased Gross Margins: | | | | | | |
Customer consumption (non-weather) | | 1,166 |
| | 714 |
| | 0.05 |
|
Implementation of new rates for Eastern Shore* | | 1,020 |
| | 625 |
| | 0.04 |
|
Retail propane margins | | 440 |
| | 270 |
| | 0.02 |
|
GRIP* | | 406 |
| | 249 |
| | 0.02 |
|
Natural gas growth (excluding service expansions) | | 347 |
| | 213 |
| | 0.01 |
|
Eight Flags' CHP plant | | 304 |
| | 186 |
| | 0.01 |
|
Pricing amendments to Aspire Energy's long-term agreements | | 291 |
| | 178 |
| | 0.01 |
|
Higher wholesale propane volumes and margins | | 271 |
| | 166 |
| | 0.01 |
|
| | 4,245 |
|
| 2,601 |
|
| 0.17 |
|
Decreased (Increased) Other Operating Expenses: | | | | | | |
Higher depreciation, asset removal and property tax costs due to new capital investments | | (1,710 | ) | | (1,047 | ) | | (0.07 | ) |
Lower outside services and facilities maintenance costs | | 1,678 |
| | 1,028 |
| | 0.07 |
|
Higher payroll expense | | (913 | ) | | (559 | ) | | (0.04 | ) |
Lower benefit and other employee-related expenses | | 295 |
| | 181 |
| | 0.01 |
|
Eight Flags' operating expenses | | 293 |
| | 179 |
| | 0.01 |
|
| | (357 | ) |
| (218 | ) |
| (0.02 | ) |
| | | | | | |
Net other changes | | (349 | ) |
| (96 | ) | | (0.01 | ) |
| | (349 | ) | | (96 | ) | | (0.01 | ) |
| | | | | | |
EPS impact of increase in outstanding shares due to September 2016 offering | | — |
| | — |
| | (0.02 | ) |
Third Quarter of 2017 Reported Results | | $ | 11,157 |
|
| $ | 6,833 |
|
| $ | 0.42 |
|
*See the Major Projects and Initiatives table.
Our net income for the nine months ended September 30, 2017 was $32.0 million, or $1.96 per share. This represents a decrease of $703,000,$789,000, or $0.04$0.18 per share, compared to the net income of $5.1$32.8 million, or $0.33$2.14 per share, as reported for the same quarterperiod in 2015.2016. Operating income decreased $753,000increased $303,000 for the threenine months ended September 30, 2016. Gross margin increased by $4.7 million, although other operating expenses increased by $5.5 million. The increase in other operating expenses, in part, reflects the fact that the higher expenses to support growth of our businesses are largely recognized equally across the year, while the margin from this growth is more concentrated in the heating season during the fourth and first quarters.2017.
| | | | Three Months Ended | | | | Nine Months Ended | | |
| | September 30, | | Increase | | September 30, | | Increase |
| | 2016 | | 2015 | | (decrease) | | 2017 | | 2016 | | (decrease) |
(in thousands except per share) | | | | | | | | | | | | |
Business Segment: | | | | | | | | | | | | |
Regulated Energy segment | | $ | 13,115 |
| | $ | 11,828 |
| | $ | 1,287 |
| | $ | 51,915 |
| | $ | 52,660 |
| | $ | (745 | ) |
Unregulated Energy segment | | (3,080 | ) | | (1,022 | ) | | (2,058 | ) | | 10,504 |
| | 9,267 |
| | 1,237 |
|
Other businesses and eliminations | | 121 |
| | 103 |
| | 18 |
| | 161 |
| | 350 |
| | (189 | ) |
Operating Income | | $ | 10,156 |
| | $ | 10,909 |
| | $ | (753 | ) | | $ | 62,580 |
| | $ | 62,277 |
| | $ | 303 |
|
Other (expense) income, net | | (28 | ) | | 36 |
| | (64 | ) | |
Other expense, net | | | (643 | ) | | (68 | ) | | (575 | ) |
Interest charges | | 2,722 |
| | 2,492 |
| | 230 |
| | 9,133 |
| | 7,996 |
| | 1,137 |
|
Pre-tax Income | | 7,406 |
| | 8,453 |
| | (1,047 | ) | | 52,804 |
| | 54,213 |
| | (1,409 | ) |
Income taxes | | 2,990 |
| | 3,334 |
| | (344 | ) | | 20,781 |
| | 21,401 |
| | (620 | ) |
Net Income | | $ | 4,416 |
| | $ | 5,119 |
| | $ | (703 | ) | | $ | 32,023 |
| | $ | 32,812 |
| | $ | (789 | ) |
Earnings Per Share of Common Stock | | | | | | | | | | | | |
Basic | | $ | 0.29 |
| | $ | 0.34 |
| | $ | (0.05 | ) | | $ | 1.96 |
| | $ | 2.14 |
| | $ | (0.18 | ) |
Diluted | | $ | 0.29 |
| | $ | 0.33 |
| | $ | (0.04 | ) | | $ | 1.96 |
| | $ | 2.14 |
| | $ | (0.18 | ) |
Key variances, between the third quarter of 2015nine months ended 2017 and the third quarter ofnine months ended 2016, included:
|
| | | | | | | | | | | | |
(in thousands, except per share data) | | Pre-tax Income | | Net Income | | Earnings Per Share |
Third Quarter of 2015 Reported Results | | $ | 8,453 |
| | $ | 5,119 |
| | $ | 0.33 |
|
| | | | | | |
Increased (Decreased) Gross Margins: | | | | | | |
Eight Flags* | | 2,033 |
| | 1,212 |
| | 0.08 |
|
Service expansions* | | 1,577 |
| | 940 |
| | 0.06 |
|
Natural gas growth (excluding service expansions) | | 943 |
| | 562 |
| | 0.04 |
|
GRIP* | | 920 |
| | 549 |
| | 0.04 |
|
Implementation of Delaware Division interim rates* | | 469 |
| | 280 |
| | 0.02 |
|
Lower retail propane margins | | (414 | ) | | (247 | ) | | (0.02 | ) |
Lower margins for Xeron | | (413 | ) | | (246 | ) | | (0.02 | ) |
Aspire Energy* | | (407 | ) | | (243 | ) | | (0.02 | ) |
| | 4,708 |
| | 2,807 |
| | 0.18 |
|
Decreased (Increased) Other Operating Expenses: | | | | | | |
Higher payroll and benefits costs | | (1,830 | ) | | (1,091 | ) | | (0.07 | ) |
Eight Flags operating expenses | | (1,065 | ) | | (635 | ) | | (0.04 | ) |
Higher outside services costs | | (928 | ) | | (553 | ) | | (0.04 | ) |
Higher facility maintenance | | (601 | ) | | (358 | ) | | (0.02 | ) |
Higher depreciation, asset removal and property tax costs | | (466 | ) | | (278 | ) | | (0.02 | ) |
| | (4,890 | ) | | (2,915 | ) | | (0.19 | ) |
Interest charges | | (230 | ) | | (137 | ) | | (0.01 | ) |
Net Other Changes | | (635 | ) | | (458 | ) | | (0.02 | ) |
Third Quarter of 2016 Reported Results | | $ | 7,406 |
| | $ | 4,416 |
| | $ | 0.29 |
|
|
| | | | | | | | | | | | |
(in thousands, except per share data) | | Pre-tax Income | | Net Income | | Earnings Per Share |
Nine Months Ended September 30, 2016 Reported Results | | $ | 54,213 |
| | $ | 32,812 |
| | $ | 2.14 |
|
| | | | | | |
Adjusting for unusual items: | | | | | | |
Weather impact | | (1,782 | ) | | (1,081 | ) | | (0.07 | ) |
Wind-down and absence of loss from Xeron operations | | (341 | ) | | (207 | ) | | (0.01 | ) |
| | (2,123 | ) | | (1,288 | ) | | (0.08 | ) |
Increased Gross Margins: | | | | | | |
Eight Flags' CHP plant | | 4,721 |
| | 2,863 |
| | 0.19 |
|
Natural gas marketing | | 1,760 |
| | 1,067 |
| | 0.07 |
|
GRIP* | | 1,619 |
| | 982 |
| | 0.06 |
|
Natural gas growth (excluding service expansions) | | 1,574 |
| | 955 |
| | 0.06 |
|
Service expansions* | | 1,371 |
| | 831 |
| | 0.05 |
|
Pricing amendments to Aspire Energy's long-term agreements | | 1,143 |
| | 693 |
| | 0.04 |
|
Implementation of new rates for Eastern Shore* | | 1,020 |
| | 619 |
| | 0.04 |
|
Wholesale propane margins | | 728 |
| | 441 |
| | 0.03 |
|
Customer consumption (non-weather) | | 700 |
| | 425 |
| | 0.03 |
|
Implementation of Delaware Division settled rates | | 249 |
| | 151 |
| | 0.01 |
|
| | 14,885 |
| | 9,027 |
| | 0.58 |
|
Increased Other Operating Expenses: | | | | | | |
Higher depreciation, asset removal and property tax costs due to new capital investments | | (4,251 | ) | | (2,578 | ) | | (0.17 | ) |
Higher payroll expense | | (3,074 | ) | | (1,864 | ) | | (0.12 | ) |
Eight Flags' operating expenses | | (2,821 | ) | | (1,711 | ) | | (0.11 | ) |
Higher benefit and other employee-related expenses | | (1,669 | ) | | (1,012 | ) | | (0.07 | ) |
Higher regulatory expenses associated with rate filings | | (855 | ) | | (519 | ) | | (0.03 | ) |
Higher outside services and facilities maintenance costs | | (318 | ) | | (193 | ) | | (0.01 | ) |
| | (12,988 | ) | | (7,877 | ) | | (0.51 | ) |
| | | | | | |
Interest charges | | (1,136 | ) | | (689 | ) | | (0.04 | ) |
Net other changes | | (47 | ) | | 38 |
| | (0.01 | ) |
| | (1,183 | ) | | (651 | ) | | (0.05 | ) |
| | | | | | |
EPS impact of increase in outstanding shares due to September 2016 offering | | — |
| | — |
| | (0.12 | ) |
Nine Months Ended September 30, 2017 Reported Results | | $ | 52,804 |
|
| $ | 32,023 |
|
| $ | 1.96 |
|
*See the Major Projects and Initiatives table.
Our net income for the nine months ended September 30, 2016 was $32.8 million, or $2.14 per share. This represents an increase of $291,000 or a decrease of $0.02 per share, compared to net income of $32.5 million, or $2.16 per share, as reported for the same period in 2015. Our growth projects and initiatives generated earnings that were offset by the effect of warmer weather, primarily in the normally colder first quarter, as well as the $1.4 million lower net settlement gain associated with the customer billing system. The warmer weather reduced year-to-date earnings per share by $0.31 compared to the same period last year.
|
| | | | | | | | | | | | |
| | Nine Months Ended | | Increase |
| | September 30, | | (decrease) |
| | 2016 | | 2015 | | |
(in thousands except per share) | | | | | | |
Business Segment: | | | | | | |
Regulated Energy segment | | $ | 52,660 |
| | $ | 47,616 |
| | $ | 5,044 |
|
Unregulated Energy segment | | 9,267 |
| | 13,666 |
| | (4,399 | ) |
Other businesses and eliminations | | 350 |
| | 305 |
| | 45 |
|
Operating Income | | $ | 62,277 |
| | $ | 61,587 |
| | 690 |
|
Other (expense) income, net | | (68 | ) | | (3 | ) | | (65 | ) |
Interest charges | | 7,996 |
| | 7,425 |
| | 571 |
|
Pre-tax Income | | 54,213 |
| | 54,159 |
| | 54 |
|
Income taxes | | 21,401 |
| | 21,638 |
| | (237 | ) |
Net Income | | $ | 32,812 |
| | $ | 32,521 |
| | $ | 291 |
|
Earnings Per Share of Common Stock | | | | | | |
Basic | | $ | 2.14 |
| | $ | 2.16 |
| | $ | (0.02 | ) |
Diluted | | $ | 2.14 |
| | $ | 2.16 |
| | $ | (0.02 | ) |
Key variances, between the first nine months of 2015 and the first nine months of 2016, included:
|
| | | | | | | | | | | | |
(in thousands, except per share data) | | Pre-tax Income | | Net Income | | Earnings Per Share |
Nine months ended September 30, 2015 Reported Results | | $ | 54,159 |
| | $ | 32,521 |
| | $ | 2.16 |
|
Adjusting for Unusual Items: | | | | | | |
Weather impact, primarily in the first quarter | | (7,548 | ) | | (4,533 | ) | | (0.31 | ) |
Net gain from settlement agreement associated with customer billing system | | (1,367 | ) | | (821 | ) | | (0.06 | ) |
| | (8,915 | ) | | (5,354 | ) | | (0.37 | ) |
Increased (Decreased) Gross Margins: | | | | | | |
Service expansions* | | 5,516 |
| | 3,312 |
| | 0.22 |
|
GRIP* | | 3,069 |
| | 1,843 |
| | 0.12 |
|
Natural gas growth (excluding service expansions) | | 2,630 |
| | 1,579 |
| | 0.11 |
|
Eight Flags* | | 2,581 |
| | 1,550 |
| | 0.10 |
|
Lower retail propane margins | | (2,204 | ) | | (1,324 | ) | | (0.09 | ) |
Implementation of Delaware Division interim rates* | | 1,350 |
| | 811 |
| | 0.05 |
|
Natural gas marketing | | 1,062 |
| | 638 |
| | 0.04 |
|
Sandpiper SIR | | 618 |
| | 371 |
| | 0.03 |
|
| | 14,622 |
| | 8,780 |
| | 0.58 |
|
Decreased (Increased) Other Operating Expenses: | | | | | | |
Higher payroll and benefits costs | | (2,144 | ) | | (1,287 | ) | | (0.09 | ) |
Higher depreciation, asset removal and property tax costs | | (1,705 | ) | | (1,024 | ) | | (0.07 | ) |
Eight Flags operating expenses | | (1,136 | ) | | (682 | ) | | (0.05 | ) |
Higher outside services costs | | (1,100 | ) | | (661 | ) | | (0.04 | ) |
Higher facility maintenance | | (787 | ) | | (473 | ) | | (0.03 | ) |
Lower bad debt, sales and advertising | | 427 |
| | 256 |
| | 0.02 |
|
| | (6,445 | ) | | (3,871 | ) | | (0.26 | ) |
Net contribution from Aspire Energy, including impact of shares issued* | | 2,069 |
| | 1,274 |
| | 0.08 |
|
Interest Charges | | (571 | ) | | (343 | ) | | (0.02 | ) |
Net Other Changes | | (706 | ) | | (195 | ) |
| (0.03 | ) |
Nine months ended September 30, 2016 Reported Results | | $ | 54,213 |
| | $ | 32,812 |
| | $ | 2.14 |
|
*See the Major Projects and Initiatives table.
Summary of Key Factors
Major Projects and Initiatives
The following table summarizes gross margin for our major projects and initiatives recently completed since 2014 and our major projects and initiatives currently underway, but which will be completed in the future. Gross margin reflects operating revenue less cost of sales, excluding depreciation, amortization and accretion (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Margin for the Period |
| Three Months Ended | | Nine Months Ended | | Total | | | | |
| September 30, | | September 30, | | 2015 | | Estimate for |
| 2016 | | 2015 | | 2016 | | 2015 | | Margin | | 2016 | | 2017 | | 2018 |
Major projects and initiatives completed since 2014 | $ | 12,083 |
| | $ | 7,490 |
| | $ | 34,086 |
| | $ | 17,030 |
| | $ | 25,270 |
| | $ | 47,603 |
| | $ | 54,258 |
| | $ | 54,727 |
|
Major projects and initiatives underway (1) | — |
| | — |
| | — |
| | — |
| | — |
| | — |
| | 5,255 |
| | 20,238 |
|
| $ | 12,083 |
| | $ | 7,490 |
| | $ | 34,086 |
| | $ | 17,030 |
| | $ | 25,270 |
| | $ | 47,603 |
| | $ | 59,513 |
| | $ | 74,965 |
|
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Margin for the Period |
| Three Months Ended | Nine Months Ended | | Year Ended | | | | | | |
| September 30, | September 30, | | December 31, | | Estimate for |
| 2017 | | 2016 | | Variance | 2017 | | 2016 | | Variance | | 2016 | | 2017 | | 2018 | | 2019 |
Major Projects and Initiatives Recently Completed | | | | | | | | | | | | | | | | | | |
Capital Investment Projects | $ | 9,807 |
| | $ | 8,963 |
| | $ | 844 |
| $ | 29,533 |
| | $ | 21,822 |
| | $ | 7,711 |
| | $ | 29,819 |
| | $ | 35,346 |
| | $ | 31,814 |
| | $ | 32,724 |
|
Eastern Shore Rate Case (1) | 1,020 |
| | — |
| | 1,020 |
| 1,020 |
| | — |
| | 1,020 |
| | — |
| | TBD |
| | TBD |
| | TBD |
|
Settled Delaware Division Rate Case | 431 |
| | 469 |
| | (38 | ) | 1,596 |
| | 1,347 |
| | 249 |
| | 1,487 |
| | 2,250 |
| | 2,250 |
| | 2,250 |
|
Total Major Projects and Initiatives Recently Completed | 11,258 |
| | 9,432 |
| | 1,826 |
| 32,149 |
| | 23,169 |
| | 8,980 |
| | 31,306 |
| | 37,596 |
| | 34,064 |
| | 34,974 |
|
Future Major Projects and Initiatives | | | | | | | | | | | | | | | | | | |
Capital Investment Projects | | | | | | | | | | | | | | | | | | |
2017 Eastern Shore System Expansion | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — | | 126 |
| | 9,313 |
| | 15,799 |
|
Northwest Florida Expansion | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — | | — |
| | 3,484 |
| | 5,127 |
|
Other Florida Pipeline Expansions | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — | | — |
| | 2,044 |
| | 2,542 |
|
Total Future Major Projects and Initiatives | — |
| | — |
| | — |
| — |
| | — |
| | — |
| | — | | 126 |
| | 14,841 |
| | 23,468 |
|
Total | $ | 11,258 |
| | $ | 9,432 |
| | $ | 1,826 |
| $ | 32,149 |
| | $ | 23,169 |
| | $ | 8,980 |
| | $ | 31,306 |
| | $ | 37,722 |
| | $ | 48,905 |
| | $ | 58,442 |
|
(1)This represents gross margin for In January 2017, Eastern Shore filed a rate case with the FERC to recover the costs of the 2016 System Reliability Project and other investments and expenses associated with the expansion, reliability and safety initiatives completed by ESNG since its last rate settlement in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing and future margin contributions will be provided once a settlement is finalized. For the third quarter of 2017, Expansion projects.a portion of the increase in rates, implemented subject to refund in August 2017, has been recorded as revenue and the remainder has been reserved pending the settlement. See Note 3, Rates and Other Regulatory Activities, for additional information.
Major Projects and Initiatives Recently Completed Since 2014
The following table summarizes gross margin generated by our major projects and initiatives recently completed since 2014 on an individual basis (dollars in thousands):
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Margin for the Period |
| Three Months Ended | | Nine Months Ended | Total | | | | | | |
| September 30, | | September 30, | 2015 | | Estimate for |
| 2016 | | 2015 | | Variance | | 2016 | | 2015 | | Variance | Margin | | 2016 | | 2017 | | 2018 |
Acquisition: | | | | | | | | | | | | | | | | | | |
Aspire Energy | $ | 1,630 |
| | $ | 2,037 |
| | $ | (407 | ) | | $ | 8,203 |
| | $ | 3,661 |
| | $ | 4,542 |
| $ | 6,324 |
| | $ | 12,674 |
| | $ | 13,376 |
| | $ | 14,302 |
|
Natural Gas Transmission Expansions and Contracts: | | | | | | | | | | | | | | | | | | |
Short-term contracts | | | | | | | | | | | | | | | | | | |
New Castle County, Delaware | $ | 664 |
| | $ | 507 |
| | $ | 157 |
| | $ | 2,040 |
| | $ | 1,998 |
| | $ | 42 |
| $ | 2,682 |
| | $ | 2,910 |
| | $ | 2,275 |
| | $ | 714 |
|
Kent County, Delaware | 2,416 |
| | 1,055 |
| | 1,361 |
| | 6,231 |
| | 1,453 |
| | 4,778 |
| 2,270 |
| | 7,982 |
| | 1,377 |
| | — |
|
Total short-term contracts | $ | 3,080 |
| | $ | 1,562 |
| | $ | 1,518 |
| | $ | 8,271 |
| | $ | 3,451 |
| | $ | 4,820 |
| $ | 4,952 |
| | $ | 10,892 |
| | $ | 3,652 |
| | $ | 714 |
|
Long-term contracts | | | | | | | | | | | | | | | | | | |
Kent County, Delaware | 455 |
| | 463 |
| | (8 | ) | | 1,366 |
| | 1,389 |
| | (23 | ) | 1,844 |
| | 1,815 |
| | 7,629 |
| | 7,605 |
|
Polk County, Florida | 407 |
| | 340 |
| | 67 |
| | 1,221 |
| | 501 |
| | 720 |
| 908 |
| | 1,627 |
| | 1,627 |
| | 1,627 |
|
Total long-term contracts | $ | 862 |
| | $ | 803 |
| | $ | 59 |
| | $ | 2,587 |
| | $ | 1,890 |
| | $ | 697 |
| $ | 2,752 |
| | $ | 3,442 |
| | $ | 9,256 |
| | $ | 9,232 |
|
Total Expansions & Contracts | $ | 3,942 |
| | $ | 2,365 |
| | $ | 1,577 |
| | $ | 10,858 |
| | $ | 5,341 |
| | $ | 5,517 |
| $ | 7,704 |
| | $ | 14,334 |
| | $ | 12,908 |
| | $ | 9,946 |
|
Florida GRIP | $ | 2,987 |
| | $ | 2,067 |
| | $ | 920 |
| | $ | 8,383 |
| | $ | 5,314 |
| | $ | 3,069 |
| $ | 7,508 |
| | $ | 11,405 |
| | $ | 13,756 |
| | $ | 15,960 |
|
Florida Electric Rate Case | $ | 1,021 |
| | $ | 1,021 |
| | $ | — |
| | $ | 2,714 |
| | $ | 2,714 |
| | $ | — |
| $ | 3,734 |
| | $ | 3,562 |
| | $ | 3,562 |
| | $ | 3,562 |
|
Delaware Division Rate Case | $ | 469 |
| | $ | — |
| | $ | 469 |
| | $ | 1,347 |
| | $ | — |
| | $ | 1,347 |
| $ | — |
| | $ | 2,164 |
| | $ | 2,500 |
| | $ | 2,500 |
|
Eight Flags CHP Plant | $ | 2,034 |
| | $ | — |
| | $ | 2,034 |
| | $ | 2,581 |
| | $ | — |
| | $ | 2,581 |
| $ | — |
| | $ | 3,464 |
| | $ | 8,156 |
| | $ | 8,457 |
|
Total Completed Major Projects and Initiatives | $ | 12,083 |
| | $ | 7,490 |
| | $ | 4,593 |
| | $ | 34,086 |
| | $ | 17,030 |
| | $ | 17,056 |
| $ | 25,270 |
| | $ | 47,603 |
| | $ | 54,258 |
| | $ | 54,727 |
|
Aspire Energy
Aspire Energy's gross margin decreased by $407,000 for the three months ended September 30, 2016, partly due to increased deliveries and imbalance positions that favorably impacted Aspire Energy in the third quarter of 2015, which are non-recurring. Lower margin associated with system volumes and imbalance positions in third quarter of 2016 also contributed to the decrease.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Gross Margin for the Period |
| Three Months Ended | Nine Months Ended | Year Ended | | | | | | |
| September 30, | September 30, | December 31, | | Estimate for |
| 2017 | | 2016 | | Variance | 2017 | | 2016 | | Variance | 2016 | | 2017 | | 2018 | | 2019 |
Capital Investment Projects: | | | | | | | | | | | | | | | | | |
Service Expansions: | | | | | | | | | | | | | | | | | |
Short-term contracts (Delaware) | $ | 1,283 |
| | $ | 3,080 |
| | $ | (1,797 | ) | $ | 5,140 |
| | $ | 8,271 |
| | $ | (3,131 | ) | $ | 11,454 |
| | $ | 5,642 |
| | $ | 1,096 |
| | $ | 1,096 |
|
Long-term contracts (Delaware) | 2,793 |
| | 862 |
| | 1,931 |
| 7,089 |
| | 2,587 |
| | 4,502 |
| 1,815 |
| | 7,611 |
| | 7,605 |
| | 7,583 |
|
Total Service Expansions | 4,076 |
| | 3,942 |
| | 134 |
| 12,229 |
| | 10,858 |
| | 1,371 |
| 13,269 |
| | 13,253 |
| | 8,701 |
| | 8,679 |
|
Florida GRIP | 3,393 |
| | 2,987 |
| | 406 |
| 10,002 |
| | 8,383 |
| | 1,619 |
| 11,552 |
| | 13,727 |
| | 14,407 |
| | 15,085 |
|
Eight Flags' CHP Plant | 2,338 |
| | 2,034 |
| | 304 |
| 7,302 |
| | 2,581 |
| | 4,721 |
| 4,998 |
| | 8,366 |
| | 8,706 |
| | 8,960 |
|
Total Capital Investment Projects | 9,807 |
| | 8,963 |
| | 844 |
| 29,533 |
| | 21,822 |
|
| 7,711 |
| 29,819 |
| | 35,346 |
| | 31,814 |
| | 32,724 |
|
Eastern Shore Rate Case (1) | 1,020 |
| | — |
| | 1,020 |
| 1,020 |
| | — |
| | 1,020 |
| — |
| | TBD | | TBD | | TBD |
Settled Delaware Division Rate Case | 431 |
| | 469 |
| | (38 | ) | 1,596 |
| | 1,347 |
| | 249 |
| 1,487 |
| | 2,250 |
| | 2,250 |
| | 2,250 |
|
Total Major Projects and Initiatives Recently Completed | $ | 11,258 |
| | $ | 9,432 |
| | $ | 1,826 |
| $ | 32,149 |
| | $ | 23,169 |
| | $ | 8,980 |
| $ | 31,306 |
| | $ | 37,596 |
| | $ | 34,064 |
| | $ | 34,974 |
|
(1) In January 2017, Eastern Shore filed a rate case with the FERC to recover the costs of the 2016 System Reliability Project and other investments and expenses associated with the expansion, reliability and safety initiatives completed by ESNG since its last rate settlement in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing and future margin contributions will be provided once a settlement is finalized. For the nine months ended September 30, 2016, Aspire Energy generated $4.5 millionthird quarter of 2017, a portion of the increase in additional gross margin comparedrates, implemented subject to the same periodrefund in 2015. Aspire Energy's gross margin for the same period in 2015 was lower due in part to the fact that the period included only six months of results commencing on April 1, 2015. Aspire Energy also generated additional gross margin primarilyAugust 2017, has been recorded as a result of pricing amendments to long-term gas sales agreements, additional management feesrevenue and the optimization of gathering system receiptsremainder has been reserved pending the settlement. See Note 3, Rates and deliveries. As projected, this merger was accretive to earnings per share in the first full year of operations.Other Regulatory Activities, for additional information.
Service Expansions
On January 16, 2015, the Florida PSC approved a firm transportation agreement between Peninsula Pipeline and our Florida natural gas distribution division. Pursuant to this agreement, Peninsula Pipeline provides natural gas transmission service to support our expansion of natural gas distribution service in Polk County, Florida. Peninsula Pipeline began the initial phase of its service to Chesapeake Utilities' Florida natural gas distribution division in March 2015. This new service generated $67,000 and $720,000 of additional gross margin for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. When all phases of this service are complete, this expansion will generate an estimated annual gross margin of $1.6 million.
In April 2015,August 2014, Eastern Shore commenced interruptible service toentered into a precedent agreement with an electric power generator in Kent County, Delaware, to provide a 20-year OPT 90 ≤ natural gas transmission service for 45,000 Dts/d deliverable to the lateral serving the customer's facility. In July 2016, the FERC authorized Eastern Shore to construct and operate the project, which consists of 5.4 miles of 16-inch pipeline looping and new compression capability in Delaware. The interruptibleEastern Shore provided interim services to this customer pending construction of facilities. Construction of the project was completed, and long-term service concludedcommenced in December 2015 and was replaced by a short-term OPT ≤ 90 Service, whichMarch 2017. This service generated an additional gross margin of $901,000 and $4.3 million$106,000 during the three and nine months ended September 30, 2016, respectively,2017 compared to the same periodsperiod in 2015. The short-term OPT ≤ 90 Service2016. There was no incremental margin change during the third quarter as the margin generated from the permanent services equated to the margin generated from providing interim services during the third quarter of 2016. This service is expected to be replaced by a 20-year contractgenerate gross margin of $7.0 million for OPT ≤ 90 Service in2017 and between $5.8 million and $7.8 million annually through the first quarterremaining term of 2017.the agreement.
On October 13,In December 2015, Eastern Shore submitted an application to the FERC approved Eastern Shore's application to make certain measurementmeter tube and control valve replacements 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. In December 2015, the FERC authorized Eastern Shore to proceed with thisThe project which was completed and placed in service in March 2016. Approximately 8535 percent of the increased capacity has been subscribed on a short-term firm service basis.basis through October 2017. This service generated an additional gross margin of $617,000$80,000 and $744,000$1.3 million for the three and nine months ended September 30, 2016,2017, respectively, compared to the same periods in 2015, and is expected to generate approximately $1.4 million in additional gross margin for the year.2016. The remaining capacity is available for firm or interruptible service.
GRIP
GRIP is a natural gas pipe replacement program approved by the Florida PSC, designed to expedite the replacement of qualifying distribution mains and services (any material other than coated steel or plastic) to enhance the reliability and integrity of the Florida natural gas distribution systems. This program allows recovery, through regulated rates, of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of the mains and services. Since the program's inception of the program in August 2012, we have invested $97.3$110.5 million to replace 209240 miles of qualifying distribution mains, including $20.4$7.6 million during the first nine months of 2016. We expect to invest an additional $650,000 in this program during the remainder of 2016.2017. The increased investment in GRIP generated additional gross margin of $920,000$406,000 and $3.1$1.6 million for the three and nine months ended September 30, 2016,2017, respectively, compared to the same periods in 2015.
2016.
Eight FlagsFlags' CHP plant
In June 2016, Eight Flags completed construction of a CHP plant on Amelia Island, Florida. This CHP plant, which consists of a natural-gas-fired turbine and associated electric generator, produces approximately 20 megawattsMWH of base load power and includes a heat recovery steam generator capable of providing approximately 75,000 pounds per hour of residual steam. OnIn June 13, 2016, Eight Flags began selling power generated from the CHP plant to FPU, our wholly-owned subsidiary, pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. OnIn July 1, 2016, it also started selling steam to anthe industrial customer that owns the property on which Eight Flags' CHP plant is located, pursuant to a separate 20-year contract.
The CHP plant is powered by natural gas transported by FPU through its distribution system.system and by Peninsula Pipeline. For the three and nine months ended September 30, 2017, Eight Flags and other affiliates of Chesapeake Utilities generated $2.0 million$304,000 and $2.6$4.7 million, in additional gross margin as a result of these new services that began in June 2016. This amount includes gross margin of $7,000 and $534,000, for the three and nine months ended September 30, 2016 in which the CHP was operational. This amount includes gross margin of $464,000 and $892,000, for the three and nine months ended September 30, 2016, attributed2017, respectively, attributable to natural gas distribution and transportation services provided by our affiliates. On a consolidated basis, this project is expected to generate approximately $8.2 million in annual gross margin in 2017, which could fluctuate based upon various factors, including, but not limited to the quantity of steam delivered and the CHP plant’s hours of operations.plant by Chesapeake Utilities' regulated affiliates.
System Reliability Project
Major Projects and Initiatives Underway
White Oak Mainline Expansion Project:In August 2014, Eastern Shore entered into a precedent agreement with an electric power generator in Kent County, Delaware, to provide a 20-year natural gas transmission service for 45,000 Dts/d for the customer's facility, upon the satisfaction of certain conditions. This new service will be provided as a long-term OPT ≤ 90 Service and is expected to generate at least $5.8 million in annual gross margin. In November 2014, Eastern Shore requested authorization by the FERC to construct 5.4 miles of 16-inch pipeline looping and 3,550 horsepower of new compression in Delaware to provide this service. As previously discussed, during the three and nine months ended September 30, 2016, compared to the same periods in 2015, we generated $901,000 and $4.3 million, respectively, in additional gross margin by providing interruptible service and short-term OPT ≤ 90 Service to this customer. On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizingauthorized Eastern Shore to construct and operate the proposed White Oak Mainline Project. Construction of the project is underway.
System Reliability Project:On May 22, 2015, Eastern Shore submitted an application to the FERC, seeking authorization to construct, own and operateProject, which consisted of approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system.A 2.5 mile looping segment was completed and placed into service in December 2016. The total project will benefit allremaining looping and the new compressor were completed and placed into service in the second quarter of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project and an order granting the requested authorization.2017. This project will bewas included in Eastern Shore's upcomingJanuary 2017 base rate case filing.filing with the FERC. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund pending final resolution of the base rate case.
Major Projects and Initiatives Currently Underway
Northwest Florida Expansion Project
Peninsula Pipeline and FPU's natural gas division are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida natural gas division. We entered into agreements to serve two industrial customers and are currently marketing to other potential customers located close to the facilities. The estimated annual gross margin associated with this project, assuming recoveryonce in the 2017 rate case,service, is approximately $4.5$5.1 million. On July 21, 2016,
New Smyrna Beach, Florida Project
Peninsula Pipeline is constructing a pipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consists of 14 miles of transmission line from the FERC issued a certificate of public convenienceFGT interconnect that will be operated by Peninsula Pipeline and necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. Construction of thewill serve FPU natural gas distribution customers. The estimated annual gross margin associated with this project, once in service, is underway.approximately $1.4 million.
2017 Expansion Project:Project On
In May 12, 2016, Eastern Shore submitted a request to the FERC to initiate the FERC's pre-filing proceduresprocess for its proposed 2017 Expansion Project. Since the time the pre-filing was initiated,This project, which will expand Eastern Shore has finalized market participation for the project. Seven of Eastern Shore’s existing customers have signed Precedent Agreements. As a result, the projectShore's firm service capacity by 26 percent, will provide 61,162 Dts/d of additional firm natural gas transportation deliverabilityservice on Eastern Shore’sShore'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 ofsystem with an additional 3,550 horsepower compressor unit52,500 Dts/d of firm transportation service at certain Eastern Shore’sShore receipt facilities pursuant to precedent agreements Eastern Shore entered into with existing Daleville compressor stationcustomers. We expect to invest approximately $115.0 million in Chester County, Pennsylvania;this expansion project, and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Thefor the project willto generate approximately $15.7$15.8 million of gross margin in the first full year after the new transportation services go into effect. On October 4, 2017, the FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 expansion project.
Other major factors influencing gross margin
Weather and Consumption
Although weather was not a significant factorTemperature variation in 2017 negatively impacted our earnings. Compared to the secondprior year, cooler temperatures in Florida during the third quarter of 2017, reduced gross margin by $333,000, and third quarters, warmer temperatures in all of our service territories during the first threenine months of 2017, reduced gross margin by $1.8 million, respectively. Warmer than normal temperatures for the year, compared to temperatures in 2015, had a significant impact on the our earnings. Lower customer consumption, directly attributable to warmer temperatures during thequarter and nine months ended September 30, 2016,2017 reduced gross margin by $7.5$193,000 and $4.3 million, compared to the same period in 2015.respectively. The following tables summarize thetable summarizes HDD and CDD informationvariances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 20162017 and 2015 resulting from weather fluctuations in those periods.2016.
HDD and CDD Information
|
| | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | Nine Months Ended | | |
| September 30, | | | | September 30, | | |
| 2016 | | 2015 | | Variance | | 2016 | | 2015 | | Variance |
Delmarva | | | | | | | | | | | |
Actual HDD | 11 |
| | 41 |
| | (30 | ) | | 2,590 |
| | 3,249 |
| | (659 | ) |
10-Year Average HDD ("Delmarva Normal") | 65 |
| | 65 |
| | — |
| | 2,919 |
| | 2,908 |
| | 11 |
|
Variance from Delmarva Normal | (54 | ) | | (24 | ) | | | | (329 | ) | | 341 |
| | |
Florida | | | | | | | | | | | |
Actual HDD | — |
| | — |
| | — |
| | 646 |
| | 501 |
| | 145 |
|
10-Year Average HDD ("Florida Normal") | — |
| | — |
| | — |
| | 553 |
| | 557 |
| | (4 | ) |
Variance from Florida Normal | — |
| | — |
| |
| | 93 |
| | (56 | ) | |
|
Ohio (1) | | | | |
| | | | | |
|
Actual HDD | 65 |
| | 78 |
| | (13 | ) | | 3,747 |
| | 710 |
| | 3,037 |
|
10-Year Average HDD ("Ohio Normal") | 137 |
| | 143 |
| | (6 | ) | | 3,979 |
| | 811 |
| | 3,168 |
|
Variance from Ohio Normal | (72 | ) | | (65 | ) | | | | (232 | ) | | (101 | ) | | |
Florida | | | | | | | | | | | |
Actual CDD | 1,523 |
| | 1,591 |
| | (68 | ) | | 2,737 |
| | 2,827 |
| | (90 | ) |
10-Year Average CDD ("Florida CDD Normal") | 1,523 |
| | 1,524 |
| | (1 | ) | | 2,548 |
| | 2,506 |
| | 42 |
|
Variance from Florida CDD Normal | — |
| | 67 |
| | | | 189 |
| | 321 |
| | |
(1)HDD for Ohio is presented from April 1, 2015 through September 30, 2015. |
| | | | | | | | | | | | | | | | | |
| Three Months Ended | | | | Nine Months Ended | | |
| September 30, | | | | September 30, | | |
| 2017 | | 2016 | | Variance | | 2017 | | 2016 | | Variance |
Delmarva | | | | | | | | | | | |
Actual HDD | 16 |
| | 11 |
| | 5 |
| | 2,262 |
| | 2,590 |
| | (328 | ) |
10-Year Average HDD ("Delmarva Normal") | 62 |
| | 65 |
| | (3 | ) | | 2,845 |
| | 2,919 |
| | (74 | ) |
Variance from Delmarva Normal | (46 | ) | | (54 | ) | | | | (583 | ) | | (329 | ) | | |
Florida | | | | | | | | | | | |
Actual HDD | — |
| | — |
| | — |
| | 298 |
| | 514 |
| | (216 | ) |
10-Year Average HDD ("Florida Normal") | — |
| | — |
| | — |
| | 602 |
| | 553 |
| | 49 |
|
Variance from Florida Normal | — |
| | — |
| |
| | (304 | ) | | (39 | ) | |
|
Ohio | | | | |
| | | | | |
|
Actual HDD | 80 |
| | 39 |
| | 41 |
| | 3,072 |
| | 3,596 |
| | (524 | ) |
10-Year Average HDD ("Ohio Normal") | 92 |
| | 103 |
| | (11 | ) | | 3,866 |
| | 3,865 |
| | 1 |
|
Variance from Ohio Normal | (12 | ) | | (64 | ) | | | | (794 | ) | | (269 | ) | | |
Florida | | | | | | | | | | | |
Actual CDD | 1,526 |
| | 1,679 |
| | (153 | ) | | 2,606 |
| | 2,792 |
| | (186 | ) |
10-Year Average CDD ("Florida CDD Normal") | 1,542 |
| | 1,523 |
| | 19 |
| | 2,579 |
| | 2,548 |
| | 31 |
|
Variance from Florida CDD Normal | (16 | ) | | 156 |
| | | | 27 |
| | 244 |
| | |
Propane pricesOperations
Lower retailOur Florida and Delmarva propane margins per gallon on the Delmarva Peninsula decreased gross margin by $344,000distribution operations added $2.0 million and $2.2$1.4 million, for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. Margins per retail gallon returned to more normal levels, driven principally by lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have continued to assume more normal levels of margins in our long-term financial plans and forecasts.
In Florida, retail propane margins per gallon, generated $70,000 of lower margin and $61,000 of additional grossincremental margin for the three and nine months ended September 30, 2016,2017, respectively, compared to the same periods in 2015.2016. Higher volumes sold to retail customers and improved margins due to effective supply management activities generated $905,000 and $440,000, in incremental margin, for the three months ended September 30, 2017, respectively, compared to the same period in 2016 and higher service revenue added $187,000 in additional margin, during the quarter.
These market conditions, which are influenced by competitionFor the nine months ended September 2017, higher volumes sold to retail customers and improved margins due to effective supply management activities generated $142,000 and $121,000, in incremental margin, respectively, compared to the same period in 2016 and higher service revenue added $244,000, in additional margin during the period.
Wholesale propane margins increased, generating additional gross margin of $271,000 and $728,000 for the three and nine months ended September 30, 2017, respectively, due primarily to higher volumes sold and improved margins resulting from supply management activities.
PESCO
PESCO provides natural gas supply and supply management services to residential, commercial, industrial and wholesale customers. PESCO operates primarily in Florida, on the Delmarva Peninsula, in Ohio, and, as a result of the recent acquisition of certain operating assets of ARM, in western Pennsylvania. PESCO competes with regulated utilities and other propane suppliersunregulated third-party marketers to sell natural gas supplies directly to residential, commercial and industrial customers through competitively-priced contracts. PESCO does not currently own or operate any natural gas transmission or distribution assets but sells gas that is delivered to retail, commercial or wholesale customers through affiliated and non-affiliated local distribution company systems and transmission pipelines.
In 2017, our Delmarva natural gas distribution operations entered into asset management agreements with PESCO to manage a portion of their natural gas transportation and storage capacity. The asset management agreements were effective April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of these agreements, PESCO manages capacity on regional pipelines as well as third-party storage contracts for our Delmarva natural gas distribution operations in conjunction with PESCO's asset management services.
For the availabilitythree months ended September 30, 2017, PESCO's gross margin increased by $56,000. For the nine months ended September 30, 2017, PESCO generated additional gross margin of $1.8 million compared to the same period in 2016, as a result
of revenues from a supplier agreement with a customer in Ohio, which expired on March 31, 2017, as well as additional customers in Florida, partially offset by lower margin in the Mid-Atlantic region, primarily during the first quarter of 2017.
Xeron
As disclosed previously, Xeron's operations were wound down during the second quarter of 2017. As a result, Xeron did not generate an operating loss during the third quarter of 2017 and pricewill not report operating results during the fourth quarter of alternative energy sources, may fluctuate based on changes2017 or subsequent years. During the third quarter of 2016, Xeron generated a pre-tax loss of $486,000. On a year-to-date basis, Xeron's pre-tax operating loss increased by $375,000, compared to the same period in demand, supply2016, driven primarily by non-recurring employee severance costs and other energy commodity prices.costs associated with the termination of leased office space in Houston, Texas. The Company does not anticipate incurring any additional costs that will have a material impact associated with winding down Xeron's operations.
Other Natural Gas Growth - Distribution Operations
In addition to service expansions, the natural gas distribution operations on the Delmarva Peninsula generated $253,000$379,000 and $1.1$1.0 million in additional gross margin for the three and nine months ended September 30, 2016,2017, respectively, compared to the same periods in 2015,2016, due to an increase in residential, commercial and industrial customers served. The average number of residential customers on the Delmarva Peninsula increased by 3.7 percent and 3.8 percent during the three and nine months ended September 30, 2016, increased by 4.2 percent and 3.5 percent,2017, respectively, compared to the same periods in 2015.2016. The natural gas distribution operations in Florida generated $350,000$187,000 and $1.1$1.2 million in additional gross margin for the three and nine months ended September 30, 2016,2017, respectively, compared to the same periods in 2015,2016, due primarily to an increase in commercial and industrial customers in Florida.
Regulatory Proceedings
Delaware Division rate caseRate Case
OnIn December 21, 2015, our Delaware Division filed an application with2016, the Delaware PSC forapproved a base rate increase and certainsettlement agreement, which, among other changes to its tariff. We proposedthings, provided for an increase of approximately $4.7 million, or nearly ten percent, in our Delaware division revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growthof $2.25 million and a rate of return on common equity of 9.75 percent. The new authorized rates went into effect on January 1, 2017. For the three months ended September 30, 2017, compared to the same period in 2016, revenue normalization mechanism for residentialdecreased by $38,000, reflecting the variance between settled and small commercial customers. We expect a decision oninterim rates. For the application duringnine months ended September 30, 2017 compared to 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,same period in 2016, ("Phase I"). We recognizedwe recorded incremental revenue of approximately $469,000 ($280,000 net$249,000 related to the rate case. Any amounts collected through 2016 interim rates in excess of tax)the respective portion of the $2.25 million were refunded to the ratepayers in March 2017.
Eastern Shore Rate Case
In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million, resulting in an overall requested revenue increase of approximately $18.9 million and $1.4a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.
On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $1.0 million ($817,000 net of tax) for the three and nine months ended September 30, 2016, respectively.2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until resolution of the rate case. Settlement discussions continue with other parties to the case.
In addition,Investing for Future Growth
To support and continue our Delaware Divisiongrowth, we have expanded, and will continue to expand, our resources and capabilities. Eastern Shore previously expanded, and continues to significantly expand, its transmission system, which require additional staffing. We requested recovery of most of Eastern Shore's increased staffing costs in its 2017 rate case.Growth in non-regulated energy businesses, including Aspire Energy, PESCO and received approval on July 26, 2016 fromEight Flags, also requires additional staff as well as corporate resources to support the Delaware PSCincreased level of business operations. Finally, to implement revised interim rates totalingallow us to continue to identify and move growth initiatives forward and to assist in developing additional initiatives, staffing and resources have been added in our corporate shared services departments. For the three and nine months ended September 30, 2017, our staffing and associated costs increased by $617,000 and $4.7 million, (equalrespectively, or three percent and nine percent, respectively, compared to the initial rate increasesame periods in our application) annualized for usage on2016. We are prudently managing the pace 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 impactmagnitude of the potential additional revenue relatedinvestments being made, while ensuring that we appropriately expand our human resources and systems capabilities to the Phase II rate increase until the Delaware PSC issues its approval in a final ruling.
capitalize on future growth opportunities.
Regulated Energy Segment
For the quarter ended September 30, 20162017 compared to the quarter ended September 30, 20152016
| | | | Three Months Ended | | | | Three Months Ended | | |
| | September 30, | | Increase | | September 30, | | Increase |
| | 2016 | | 2015 | | (decrease) | | 2017 | | 2016 | | (decrease) |
(in thousands) | | | | | | | | | | | | |
Revenue | | $ | 70,019 |
| | $ | 63,796 |
| | $ | 6,223 |
| | $ | 69,703 |
| | $ | 70,019 |
| | $ | (316 | ) |
Cost of sales | | 24,644 |
| | 23,161 |
| | 1,483 |
| | 22,794 |
| | 24,644 |
| | (1,850 | ) |
Gross margin | | 45,375 |
| | 40,635 |
| | 4,740 |
| | 46,909 |
| | 45,375 |
| | 1,534 |
|
Operations & maintenance | | 22,912 |
| | 19,882 |
| | 3,030 |
| | 21,149 |
| | 22,912 |
| | (1,763 | ) |
Depreciation & amortization | | 6,346 |
| | 6,129 |
| | 217 |
| | 7,338 |
| | 6,346 |
| | 992 |
|
Other taxes | | 3,002 |
| | 2,796 |
| | 206 |
| | 3,254 |
| | 3,002 |
| | 252 |
|
Other operating expenses | | 32,260 |
| | 28,807 |
| | 3,453 |
| | 31,741 |
| | 32,260 |
| | (519 | ) |
Operating income | | $ | 13,115 |
| | $ | 11,828 |
| | $ | 1,287 |
| | $ | 15,168 |
| | $ | 13,115 |
| | $ | 2,053 |
|
Operating income for the Regulated Energy segment for the quarterthree months ended September 30, 20162017 was $13.1$15.2 million, an increase of $1.3$2.1 million or 10.9 percent, compared to the same quarterperiod in 2015.2016. The increased operating income was due primarily to an increase inresulted from increased gross margin of $4.7$1.5 million partially offset by an increaseand a decrease in operating expenses of $3.4 million.$519,000.
Gross Margin
Items contributing to the quarter-over-quarter increase of $4.7$1.5 million, or 11.73.4 percent, in gross margin are listed in the following table:
|
| | | |
(in thousands) | |
|
Gross margin for the three months ended September 30, 2015 | $ | 40,635 |
|
Factors contributing to the gross margin increase for the three months ended September 30, 2016: | |
Service expansions | 1,577 |
|
Natural gas growth (excluding service expansions) | 943 |
|
Additional revenue from GRIP in Florida | 920 |
|
Implementation of Delaware Division interim rates | 469 |
|
Margin from service to Eight Flags | 464 |
|
Sandpiper SIR | 226 |
|
Other | 141 |
|
Gross margin for the three months ended September 30, 2016 | $ | 45,375 |
|
|
| | | |
(in thousands) | |
|
Gross margin for the three months ended September 30, 2016 | $ | 45,375 |
|
Factors contributing to the gross margin increase for the three months ended September 30, 2017: | |
Implementation of Eastern Shore rates | 1,020 |
|
Additional Revenue from GRIP in Florida | 406 |
|
Natural gas growth (excluding service expansions) | 347 |
|
Other | (239 | ) |
Gross margin for the three months ended September 30, 2017 | $ | 46,909 |
|
The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the foregoing table.
Implementation of Eastern Shore Rates
Service Expansions
IncreasedEastern Shore generated additional gross margin from natural gas service expansions was generated primarily from the following:
$901,000 attributable to $1.9of $1.0 million from the short-term OPT ≤ 90 Service that commencedimplementation of new rates as a result of its rate case filing. See Note 3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Additional Revenue from GRIP in December 2015 to an electric power generatorFlorida
Increased investment in Kent County, Delaware and offset by a $1.0 million decrease in gross margin from the conclusion of the interruptible service Eastern Shore provided this customer in 2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service in the first quarter of 2017.
$617,000 from short-term firm service that commenced in March 2016, following certain measurement and related improvements to Eastern Shore's interconnect with TETLP that increased its natural gas receipt capacity from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. This service will generate approximately $1.4 million inGRIP generated additional gross margin of $406,000 for the three months ended September 30, 2017, compared to the same period in 2016. The remaining capacity is available for firm or interruptible service.
Natural Gas Growth (excluding service expansions)
Increased gross margin of $943,000$347,000 from other growth in natural gas (excluding service expansions) was generated primarily from the following:
$368,000379,000 from Eastern Shore interruptible service provided toa four-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers;
$350,000187,000 from Florida natural gas customer growth, due primarily to new services to commercial and industrial customers; and
which were partially offset by $219,000 in decreased margin from Eastern Shore's interruptible services.
Other Operating Expenses
Other operating expenses decreased by $519,000. The significant factors contributing to the decrease in other operating expenses included:
$253,0001.6 million in lower costs related to outside services and facilities and maintenance costs, due primarily to lower consulting and service contractor costs;
$437,000 in lower benefits and employee-related costs (since we are self-insured for healthcare, benefits costs fluctuate depending upon filed claims);
$1.4 million in higher depreciation, asset removal and property tax costs associated with recent capital investments.
For the Nine Months Ended September 30, 2017 compared to the nine months ended September 30, 2016
|
| | | | | | | | | | | | |
| | Nine Months Ended | | |
| | September 30, | | Increase |
| | 2017 | | 2016 | | (decrease) |
(in thousands) | | | | | | |
Revenue | | $ | 238,353 |
| | $ | 226,630 |
| | $ | 11,723 |
|
Cost of sales | | 87,206 |
| | 81,184 |
| | 6,022 |
|
Gross margin | | 151,147 |
| | 145,446 |
| | 5,701 |
|
Operations & maintenance | | 67,869 |
|
| 64,673 |
| | 3,196 |
|
Depreciation & amortization | | 21,365 |
| | 18,909 |
| | 2,456 |
|
Other taxes | | 9,998 |
| | 9,204 |
| | 794 |
|
Other operating expenses | | 99,232 |
| | 92,786 |
| | 6,446 |
|
Operating income | | $ | 51,915 |
| | $ | 52,660 |
| | $ | (745 | ) |
Operating income for the Regulated Energy segment for the nine months ended September 30, 2017 was $51.9 million, a decrease of $745,000 compared to the same period in 2016. The decreased operating income was due to an increase in gross margin of $5.7 million, offset by higher operating expenses of $6.4 million. Of the total $6.4 million increase in operating expenses, $4.7 million is associated with Eastern Shore's recently completed projects as well as initiatives underway.
Gross Margin
Items contributing to the period-over-period increase of $5.7 million, or 3.9 percent, in gross margin are listed in the following table:
|
| | | |
(in thousands) | |
|
Gross margin for the nine months ended September 30, 2016 | $ | 145,446 |
|
Factors contributing to the gross margin increase for the nine months ended September 30, 2017: | |
Additional revenue from GRIP in Florida | 1,619 |
|
Natural gas growth (excluding service expansions) | 1,574 |
|
Service expansions | 1,371 |
|
Customer consumption - weather and other | (1,249 | ) |
Implementation of Eastern Shore rates | 1,020 |
|
Service to Eight Flags | 534 |
|
Implementation of Delaware Division Rates | 249 |
|
Other | 583 |
|
Gross margin for the nine months ended September 30, 2017 | $ | 151,147 |
|
The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
Additional Revenue from GRIP in Florida
Increased investment in GRIP generated additional gross margin of $1.6 million for the nine months ended September 30, 2017, compared to the same period in 2016.
Natural Gas Growth (Excluding Service Expansions)
Increased gross margin of $1.6 million from growth (excluding service expansions) was generated primarily from the following:
$1.2 million from Florida natural gas customer growth, due primarily to new services to commercial and industrial customers; and
$1.0 million from a 4.2 percentfour-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers.
Service Expansions
Additional RevenueEastern Shore generated increased gross margin of $1.4 million from GRIPnatural gas service expansions related to short-term firm service that commenced in March 2016. Following certain measurement and related improvements to Eastern Shore's interconnect with TETLP, Eastern Shore's natural gas receipt capacity from TETLP increased by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. The remaining capacity is available for firm or interruptible service.
Customer Consumption - Weather and Other
Gross margin decreased by $1.2 million from lower customer consumption of electricity and natural gas, due primarily to warmer temperatures in Florida
Additional GRIP investments and on the Delmarva Peninsula. Because Maryland and Sandpiper Energy rates include a weather normalization adjustment for residential heating and smaller commercial heating customers, these operations experienced minimal impact from the warmer weather during 2015 and 2016 by our Florida natural gas distribution operations generated $920,000 in additional gross margin in the third quarterfirst nine months of 2016, compared to the same period in 2015.2017.
Implementation of Delaware Division InterimEastern Shore Rates
Delaware DivisionEastern Shore generated additional gross margin of $469,000$1.0 million from the implementation of interimnew rates as a result of its rate case filing. See Note 4,3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Margin from serviceService to Eight Flags
We generated additional gross margin of $464,000$534,000 in the third quarter of 2016,nine months ended September 30, 2017, compared to the same period in 2015,2016, from new natural gas transmission and distribution services provided by our affiliates to our Eight Flags' CHP plant.
Sandpiper SIR
Sandpiper generated additional gross margin of $226,000, in the third quarter of 2016, compared to the same period in 2015, from a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service.
Other Operating Expenses
Other operating expenses increased by $3.4 million. The significant components of the increase in other operating expenses included:
$1.3 million in higher payroll and benefits costs for additional personnel to support growth;
$702,000 in higher outside services costs primarily associated with growth and ongoing compliance activities;
$517,000 in higher facilities costs to support growth; and
$401,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments to support growth and system integrity.
For the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015
|
| | | | | | | | | | | | |
| | Nine Months Ended | | |
| | September 30, | | Increase |
| | 2016 | | 2015 | | (decrease) |
(in thousands) | | | | | | |
Revenue | | $ | 226,630 |
| | $ | 235,438 |
| | $ | (8,808 | ) |
Cost of sales | | 81,184 |
| | 101,414 |
| | (20,230 | ) |
Gross margin | | 145,446 |
| | 134,024 |
| | 11,422 |
|
Operations & maintenance | | 64,673 |
| | 59,648 |
| | 5,025 |
|
Depreciation & amortization | | 18,909 |
| | 18,109 |
| | 800 |
|
Other taxes | | 9,204 |
| | 8,650 |
| | 554 |
|
Other operating expenses | | 92,786 |
| | 86,407 |
| | 6,379 |
|
Operating income | | $ | 52,660 |
| | $ | 47,617 |
|
| $ | 5,043 |
|
Operating income for the Regulated Energy segment for the nine months ended September 30, 2016 was $52.7 million, an increase of $5.0 million, or, 10.6 percent, compared to the same period in 2015. The increased operating income was primarily due to an increase in gross margin of $11.4 million partially offset by a $6.4 million increase in operating expenses to support growth.
Gross Margin
Items contributing to the period-over-period increase of $11.4 million, or 8.5 percent, in gross margin are listed in the following table:
|
| | | |
(in thousands) | |
Gross margin for the nine months ended September 30, 2015 | $ | 134,024 |
|
Factors contributing to the gross margin increase for the nine months ended September 30, 2016: | |
Service expansions | 5,516 |
|
Additional revenue from GRIP in Florida | 3,069 |
|
Natural gas growth (excluding service expansions) | 2,630 |
|
Implementation of Delaware Division interim rates | 1,350 |
|
Margin from service to Eight Flags | 892 |
|
Sandpiper SIR | 618 |
|
Decreased customer consumption - weather and other | (2,141 | ) |
Other | (512 | ) |
Gross margin for the nine months ended September 30, 2016 | $ | 145,446 |
|
The following is a narrative discussion of the significant items, which we believe is necessary to understand the information disclosed in the foregoing table.
Service Expansions
Increased gross margin from natural gas service expansions was generated primarily from the following:
$4.3 million attributable to $5.6 million from the short-term OPT ≤ 90 Service that commenced in December 2015 to an electric power generator in Kent County, Delaware and offset by a $1.3 million decrease in gross margin from the conclusion of the interruptible service Eastern Shore provided this customer in 2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service in the first quarter of 2017.
$744,000 from short-term firm service that commenced in March 2016, following certain measurement and related improvements to Eastern Shore's interconnect with TETLP that increased its natural gas receipt capacity from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. This service will generate approximately $1.4 million in additional gross margin in 2016. The remaining capacity is available for firm or interruptible service.
$720,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.
The foregoing gross margin increases were offset by a gross margin decrease of $243,000 resulting from a reduction in rates for a long-term firm service to an industrial customer in New Castle County, Delaware.
Additional Revenue from GRIP in Florida
Additional GRIP investments during 2015 and 2016 by our Florida natural gas distribution operations generated $3.1 million in additional gross margin during the first nine months of 2016, compared to the same period in 2015.
Natural Gas Growth (excluding service expansions)
Increased gross margin from other growth in natural gas (excluding service expansions) was generated primarily from the following:
$1.1 million from a 3.5 percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers.
$1.1 million from Florida natural gas customer growth due primarily to new services to commercial and industrial customers.
$348,000 from Eastern Shore interruptible service provided to other customers.
Implementation of Delaware Division Interim Rates
Our Delaware Division generated additional gross margin of $1.4 million from the implementation of interim rates$249,000 as a result of itsthe settlement of the rate case filing, during the first nine months of 2016.case. See Note 4,3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Margin from service to Eight Flags
We generated additional gross margin of $892,000 from new natural gas transmission and distribution services provided to our Eight Flags' CHP plant, commencing in June of 2016.
Sandpiper SIR Rates
Sandpiper generated additional gross margin of $618,000 from a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service.
Decreased Customer Consumption - Weather and Other
The above increases were partially offset by $2.1 million in lower gross margin due to reduced consumption of natural gas and electricity, largely as a result of warmer weather during the first quarter of 2016, compared to the same period in 2015.
Other Operating Expenses
Other operating expenses increased by $6.4 million. The significant components of the increase in other operating expenses included:
$2.0 million in higher payroll and benefits costs for additional personnel to support growth;
$1.4 million due to the absence of a $1.5 million gain from a customer billing system settlement, recorded in 2015, which was partially offset by an associated gain of $130,000 during the third quarter of 2016, representing an additional current portion of the contingent settlement recovery;
$1.43.5 million in higher depreciation, asset removal and property tax costs associated with recent capital investmentsinvestments;
$1.6 million in higher payroll expenses for addition personnel to support growth and system integrity;growth;
$855,000 in increased regulatory expenses, due primarily to costs associated with Eastern Shore’s rate case filing in 2017; and
$817,000722,000 in higher outside servicesbenefits and employee-related costs primarily associated with growth and ongoing compliance activities.in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed).
Unregulated Energy Segment
For the quarter ended September 30, 20162017 compared to the quarter ended September 30, 20152016
| | | | Three Months Ended | | | | Three Months Ended | | |
| | September 30, | | Increase | | September 30, | | Increase |
| | 2016 | | 2015 | | (decrease) | | 2017 | | 2016 | | (decrease) |
(in thousands) | | | | | | | | | | | | |
Revenue | | $ | 42,042 |
| | $ | 29,609 |
| | $ | 12,433 |
| | $ | 64,688 |
| | $ | 42,042 |
| | $ | 22,646 |
|
Cost of sales | | 31,840 |
| | 19,402 |
| | 12,438 |
| | 51,416 |
| | 31,840 |
| | 19,576 |
|
Gross margin | | 10,202 |
| | 10,207 |
| | (5 | ) | | 13,272 |
| | 10,202 |
| | 3,070 |
|
Operations & maintenance | | 10,975 |
| | 9,305 |
| | 1,670 |
| | 11,460 |
| | 10,975 |
| | 485 |
|
Depreciation & amortization | | 1,840 |
| | 1,483 |
| | 357 |
| | 2,001 |
| | 1,840 |
| | 161 |
|
Other taxes | | 467 |
| | 441 |
| | 26 |
| | 800 |
| | 467 |
| | 333 |
|
Other operating expenses | | 13,282 |
| | 11,229 |
| | 2,053 |
| |
Operating Loss | | $ | (3,080 | ) | | $ | (1,022 | ) | | $ | (2,058 | ) | |
Total operating expenses | | | 14,261 |
| | 13,282 |
| | 979 |
|
Operating loss | | | $ | (989 | ) | | $ | (3,080 | ) | | $ | 2,091 |
|
Operating loss for the Unregulated Energy segment for the quarterthree months ended September 30, 20162017 was $3.1 million, an increase of $2.1 million$989,000, compared to the same quarter of 2015. The Unregulated Energy segment typically reports an operating loss in the third quarter due to the seasonal nature the businesses included in this segment. Gross margin for the quarter was $10.2 million, which was more than offset by operating expenses of $13.3 million, to generate the operating loss of $3.1 million.million for same period in 2016. The decreased operating loss was due to an increase in gross margin of $3.1 million, which was offset by a $1.0 million increase in operating expenses.
Gross Margin
Items contributing to the quarter-over-quarter decreaseincrease of $5,000$3.1 million in gross margin are listed in the following table:
|
| | | | |
(in thousands) | | |
Gross margin for the three months ended September 30, 2015 | | $ | 10,207 |
|
Factors contributing to the gross margin decrease for the three months ended September 30, 2016: | | |
Eight Flags | | 1,570 |
|
Aspire Energy | | (407 | ) |
Lower margins for Xeron | | (413 | ) |
Decreased retail propane margins | | (414 | ) |
Other | | (341 | ) |
Gross margin for the three months ended September 30, 2016 | | $ | 10,202 |
|
|
| | | | |
(in thousands) | | |
Gross margin for the three months ended September 30, 2016 | | $ | 10,202 |
|
Factors contributing to the gross margin increase for the three months ended September 30, 2017: | | |
Customer Consumption - Weather and Other | | 1,165 |
|
Retail Propane Margins | | 440 |
|
Eight Flags' CHP Plant | | 297 |
|
Pricing Amendments to Aspire Energy's Long-Term Agreements | | 291 |
|
Wholesale Propane Margins | | 271 |
|
Wind-down of Xeron operations | | 233 |
|
Other | | 373 |
|
Gross margin for the three months ended September 30, 2017 | | $ | 13,272 |
|
The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the foregoing table.
Customer Consumption - Weather and Other
Gross margin increased by $1.2 million, due primarily to increased sales volumes of propane to wholesale and retail customers on the Delmarva Peninsula and higher retail propane sales volumes in Florida due primarily to the timing of deliveries.
Retail Propane Margins
Gross margin increased by $440,000, due primarily to favorable supply management activities.
Eight Flags
Eight Flags' CHP plant, which commenced operations in June 2016, generated $1.6 million$297,000 in additional gross margin.
Aspire Energy
$407,000 of decreased gross margin from Aspire Energy as a result of increased deliveries and imbalance positions that favorably impacted Aspire Energydue primarily to Eight Flags being fully on-line in the third quarter of 2015, which are non-recurring. Lower margin associated with system volumes and imbalance positions2017.
Pricing Amendments to Aspire Energy Long-Term Agreements
An increase in third quarter of 2016, also contributed to the decrease.
Lower Margins for Xeron
Xeron's gross margin decreased by $413,000 resulting from lower margins on executed trades.
Decreased Retail Propane Margins
Lower retail propane margins for our Delmarva and Florida propane distribution operations decreased gross margin by $414,000, of which $344,000 is associated with the Delmarva Peninsula propane distribution operation, as retail margins per gallon returned$291,000 was due to pricing amendments to long-term sales agreements.
Wholesale Propane Margins
Gross margin increased by $271,000, due primarily to more normal levels; accordingly, we have continued to assume more normal levelsfavorable supply management activities for the Delmarva propane distribution operations.
Xeron
The absence of margins in our long-term financial plans and forecasts. The decline inthe prior year operating loss increased gross margin was driven principally by lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term.
$233,000.
Other Operating Expenses
Other operating expenses increased by $2.1$1.0 million. The significant components of the increase in other operating expenses included:
$1.1 million in other operating expenses incurred by the Eight Flags CHP plant;
$545,000730,000 in higher payrollstaffing and benefitsassociated costs for additional personnel to support growth;growth (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed);
$347,000 in higher depreciation, amortization and property tax costs due to increased capital investments and amortization of intangible assets acquired through acquisitions in 2017; and
$225,000293,000 in higher outside services costs primarilyexpenses associated with growth and ongoing compliance activities.the incremental margin from Eight Flags
For the nine months ended September 30, 20162017 compared to the nine months ended September 30, 20152016
| | | | Nine Months Ended | | | | Nine Months Ended | | |
| | September 30, | | Increase | | September 30, | | Increase |
| | 2016 | | 2015 | | (decrease) | | 2017 | | 2016 | | (decrease) |
(in thousands) | | | | | | | | | | | | |
Revenue | | $ | 136,361 |
| | 123,164 |
| | $ | 13,197 |
| | $ | 220,462 |
| | $ | 136,361 |
| | $ | 84,101 |
|
Cost of sales | | 90,981 |
| | 77,235 |
| | 13,746 |
| | 166,635 |
| | 90,981 |
| | 75,654 |
|
Gross margin | | 45,380 |
| | 45,929 |
| | (549 | ) | | 53,827 |
| | 45,380 |
| | 8,447 |
|
Operations & maintenance | | 30,136 |
| | 26,993 |
| | 3,143 |
| | 34,971 |
| | 30,136 |
| | 4,835 |
|
Depreciation & amortization | | 4,512 |
| | 3,973 |
| | 539 |
| | 5,833 |
| | 4,512 |
| | 1,321 |
|
Other taxes | | 1,465 |
| | 1,297 |
| | 168 |
| | 2,519 |
| | 1,465 |
| | 1,054 |
|
Other operating expenses | | 36,113 |
| | 32,263 |
| | 3,850 |
| |
Operating Income | | $ | 9,267 |
| | $ | 13,666 |
| | $ | (4,399 | ) | |
Total operating expenses | | | 43,323 |
| | 36,113 |
| | 7,210 |
|
Operating income | | | $ | 10,504 |
| | $ | 9,267 |
| | $ | 1,237 |
|
Operating income for the Unregulated Energy segment for the nine months ended September 30, 20162017 was $9.3$10.5 million, a decreasean increase of $4.4$1.2 million or 32.2 percent forcompared to the same period of 2015.in 2016. The results for the first nine months includeincreased operating income was due to an increase in gross margin of $4.5$8.4 million, and otherwhich was partially offset by a $7.2 million increase in operating expenses of $2.5 million, each associated with Aspire Energy. Excluding these impacts from Aspire Energy, gross margin decreased by $5.1 million, and other operating expenses increased by $1.4 million.expenses.
Gross Margin
Items contributing to the period-over-period decreaseincrease of $549,000$8.4 million in gross margin are listed in the following table:
|
| | | | |
(in thousands) | | |
Gross margin for the nine months ended September 30, 2015 | | $ | 45,929 |
|
Factors contributing to the gross margin decrease for the nine months ended September 30, 2016: | | |
Aspire Energy | | 4,542 |
|
Eight Flags | | 1,689 |
|
Natural gas marketing | | 1,062 |
|
Lower margins for Xeron | | (419 | ) |
Decreased wholesale propane sales | | (436 | ) |
Decreased retail propane margins | | (2,204 | ) |
Decreased customer consumption - weather and other | | (4,059 | ) |
Other | | (724 | ) |
Gross margin for the nine months ended September 30, 2016 | | $ | 45,380 |
|
|
| | | | |
(in thousands) | | |
Gross margin for the nine months ended September 30, 2016 | | $ | 45,380 |
|
Factors contributing to the gross margin increase for the nine months ended September 30, 2017: | | |
Eight Flags' CHP plant | | 4,186 |
|
Natural Gas Marketing | | 1,760 |
|
Pricing Amendments to Aspire Energy's Long-Term Agreements | | 1,143 |
|
Propane Wholesale Sales | | 728 |
|
Customer consumption - weather and other | | 168 |
|
Other | | 462 |
|
Gross margin for the nine months ended September 30, 2017 | | $ | 53,827 |
|
The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the foregoing table.
Aspire Energy
Aspire Energy generated $8.2 million in gross margin compared to $3.7 million in the same period of 2015, an increase of $4.5 million. Results for the first nine months of 2015 reflect only six months of margin for Aspire Energy, which became a wholly-owned subsidiary of Chesapeake Utilities on April 1, 2015. In addition, Aspire Energy generated additional margins as a result of pricing amendments to long-term gas sales agreements, additional management fees and the optimization of gathering system receipts and deliveries.
Eight Flags
Eight Flags' CHP plant, which commenced operations in June 2016, generated $1.7$4.2 million in additional gross margin.
Natural Gas Marketing
PESCO generated $1.1 million in additional gross margin due to customer growth andof $1.8 million for the positive impact from favorable supply management and hedging activities, which generated additional gross margin.
Lower Margins for Xeron
Xeron's gross margin decreased by $419,000 resulting from lower margins on executed trades.
Decreased Propane Wholesale Sales
Gross margin decreased by $436,000 as a result of lower propane wholesale sales associated with the supply agreement between an affiliate of ESG and Sandpiper Energy. The lower sales are expected as more customers in Ocean City, Maryland and surrounding areas are converted from propane to natural gas. Lower sales due to significantly warmer weather in the first nine months of 2016ended September 30, 2017 compared to the same period in 2015, also contributed2016. The increase in gross margin was generated primarily from providing natural gas to this decrease.approximately 40,000 end users within one customer pool pursuant to the supplier agreement with Columbia Gas, which expired on March 31, 2017, as well as an increase in commercial and industrial customers served in Florida, offset by lower gross margin in the Mid-Atlantic region.
Pricing Amendments to Aspire Energy's Long-Term Agreements
Decreased RetailAn increase in gross margin of $1.1 million was due to favorable pricing amendments to long-term sales agreements, which generated $1.6 million in gross margin, offset by the absence of a one-time management fee of $560,000 paid to Aspire Energy by CGC in the first quarter of 2016.
Wholesale Propane Margins
Lower retail propane marginsGross margin increased by $728,000, due primarily to favorable supply management activities for ourthe Delmarva propane distribution operation decreased gross margin by $2.2 million, as margins per retail gallon returned to more normal levels. The decline in margin was driven principally by lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have continued to assume more normal levels of margins in our long-term financial plans and forecasts.operations.
This decrease was partially offset by $61,000 in higher retail propane margins per gallon for our Florida propane distribution operation as a result of local market conditions.
Decreased Customer Consumption - Weather and Other
Gross margin decreasedincreased by $4.1 million$168,000, due primarily to lower customer consumptionhigher sales of propane. The decrease was driven mainly by weatherpropane as a result of timing of deliveries for our propane distributions operations, coupled with increased demand for propane in Florida due to weather conditions in the third quarter of 2017. This was partially offset by the impact of warmer temperatures on the Delmarva Peninsulaweather primarily during the first ninethree months of 2016 compared to colder temperatures during the first nine months of 2015.
2017.
Other Operating Expenses
Other operating expenses increased by $3.9$7.2 million. The significant components of the increase in other operating expenses included:
$2.52.8 million in otherhigher operating expenses incurred by Aspire Energy, givenEight Flags' CHP plant in support of the margin generated;
$1.5 million in higher payroll costs for additional quarter's results includedpersonnel to support growth;
$950,000 in higher benefits and employee-related costs in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed);
$800,000 in higher depreciation expense, of which $424,000 relates to a credit adjustment in 2016 compared to only six months of resultsrecorded in conjunction with the nine months ended September 30, 2015;final valuation for Aspire Energy; and
$1.1 million350,000 in other operating expenses incurred by Eight Flags, which commenced operations in June 2016.
higher outside services costs associated primarily with growth and ongoing compliance activities.
OTHER INCOME (EXPENSE), NET
Interest Charges
For the quarter ended September 30, 20162017 compared to the quarter ended September 30, 20152016
Other income (expense), net, which includes non-operating investment income (expense), interest income, late fees charged to customers and gains or losses from the sale of assets, increased by $267,000 in the third quarter of 2017, compared to the same period in 2016, due primarily to the gain from the sale of assets within our unregulated energy businesses.
For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2017
Other income (expense), net, which includes non-operating investment income (expense), interest income, late fees charged to customers and gains or losses from the sale of assets, decreased by $575,000 for the first nine months of 2017, compared to the same period in 2016, due partly to costs associated with the termination of a lease for Xeron partially offset by the gain from the sale of assets within our unregulated energy businesses.
INTEREST CHARGES
For the quarter ended September 30, 2017 compared to the quarter ended September 30, 2016
Interest charges for the three months ended September 30, 20162017 increased by approximately $230,000,$599,000, compared to the same quarterperiod in 2015,2016, attributable to an increase of $392,000$410,000 in interest fromon long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017, and an increase of $266,000 in interest on higher short-term borrowings, partially offset by a decrease of $117,000 in interest from long-term debt.
borrowings.
For the nine months ended September 30, 20162017 compared to the nine months ended September 30, 20152016
Interest charges for the nine months ended September 30, 20162017 increased by approximately $571,000,$1.1 million, compared to the same period in 2015,2016, attributable to an increase of $1.1 million$691,000 in interest fromon higher short-term borrowings partially offset by a decreaseand an increase of $352,000$618,000 in interest fromon long-term debt.debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017.
INCOME TAXES
For the quarter ended September 30, 20162017 compared to the quarter ended September 30, 20152016
Income tax expense was $4.3 million for the three months ended September 30, 2017, compared to $3.0 million in the third quarter of 2016, compared to $3.3 millionsame period in the same quarter in 2015.2016. The slight decreaseincrease in income tax expense was due primarily to lower taxable income.an increase in our operating results. Our effective income tax rate was 40.438.8 percent and 39.440.4 percent, for the third quarter ofthree months ended September 30, 2017 and 2016, and 2015, respectively.
For the nine months ended September 30, 20162017 compared to the nine months ended September 30, 20152017
Income tax expense was $21.4$20.8 million infor the nine months ended September 30, 2016,2017, compared to $21.6$21.4 million in the same period in 2015.2016. The slight decrease in income tax expense was due primarily to lower taxable income.a decrease in our operating results. Our effective income tax rate was 39.539.4 percent and 40.039.5 percent, for the first nine months ofended September 30, 2017 and 2016, and 2015, respectively.
FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES
Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to more closely align our capital structure to target.our target capital structure.
Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered to customers throughby our natural gas, electric, and propane distribution operations and our natural gas gathering and processing operation to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $132.4 million for the nine months ended September 30, 2016 were approximately $106.3 million. 2017.
We originally budgeted $260.3 million for capital expenditures during 2017, and we currently project aggregate capital expenditures between $150.0 and $170.0of approximately $214.7 million in 2016.2017. Our current forecast by segment and by business line is shown below:
| | | Low | | High | 2017 |
(dollars in thousands) | | | | |
Regulated Energy: | | | | |
Natural gas distribution | $ | 60,000 |
| | $ | 65,000 |
| $ | 76,771 |
|
Natural gas transmission | 55,000 |
| | 60,000 |
| 93,737 |
|
Electric distribution | 10,000 |
| | 13,000 |
| 10,768 |
|
Total Regulated Energy | 125,000 |
|
| 138,000 |
| 181,276 |
|
Unregulated Energy: | | | | |
Propane distribution | 10,000 |
| | 12,000 |
| 10,458 |
|
Other unregulated energy | 10,000 |
| | 13,000 |
| 16,417 |
|
Total Unregulated Energy | 20,000 |
|
| 25,000 |
| 26,875 |
|
| | | | |
Other | 5,000 |
| | 7,000 |
| |
| | | | |
Total 2016 capital expenditures | $ | 150,000 |
|
| $ | 170,000 |
| |
Other: | | |
Corporate and other businesses | | 6,507 |
|
Total Other | | 6,507 |
|
Total 2017 Capital Expenditures | | $ | 214,658 |
|
The 2016 forecast includes expenditures for the following projects: Eight Flags' CHP plant; anticipated new facilitiescapital expenditure projection is subject to serve an electric power generator in Kent County, Delaware under the OPT ≤ 90 Service; Eastern Shore's system reliability project; additional expansions of our natural gas distributioncontinuous review and transmission systems; continued natural gas infrastructure improvement activities; expenditures for continued replacement under the Florida GRIP; replacement of several facilities and information technology systems; and other strategic initiatives and investments.
modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.
The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.
Capital Structure
We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated energy operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors.
The following table presents our capitalization, excluding and including short-term borrowings, as of September 30, 20162017 and December 31, 2015:2016:
| | | | September 30, 2016 | | December 31, 2015 | | September 30, 2017 | | December 31, 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Long-term debt, net of current maturities | | $ | 143,525 |
| | 25 | % | | $ | 149,006 |
| | 29 | % | | $ | 201,248 |
| | 30 | % | | $ | 136,954 |
| | 23 | % |
Stockholders’ equity | | 438,300 |
| | 75 | % | | 358,138 |
| | 71 | % | | 463,820 |
| | 70 | % | | 446,086 |
| | 77 | % |
Total capitalization, excluding short-term debt | | $ | 581,825 |
| | 100 | % | | $ | 507,144 |
| | 100 | % | | $ | 665,068 |
| | 100 | % | | $ | 583,040 |
| | 100 | % |
| | September 30, 2016 | | December 31, 2015 | | | | | | | | |
| | | September 30, 2017 | | December 31, 2016 |
(in thousands) | | | | | | | | | | | | | | | | |
Short-term debt | | $ | 154,490 |
| | 20 | % | | $ | 173,397 |
| | 25 | % | | $ | 203,098 |
| | 23 | % | | $ | 209,871 |
| | 26 | % |
Long-term debt, including current maturities | | 155,612 |
| | 21 | % | | 158,157 |
| | 23 | % | | 213,384 |
| | 24 | % | | 149,053 |
| | 19 | % |
Stockholders’ equity | | 438,300 |
| | 59 | % | | 358,138 |
| | 52 | % | | 463,820 |
| | 53 | % | | 446,086 |
| | 55 | % |
Total capitalization, including short-term debt | | $ | 748,402 |
| | 100 | % | | $ | 689,692 |
| | 100 | % | | $ | 880,302 |
| | 100 | % | | $ | 805,010 |
| | 100 | % |
Included in the long-term debt balances at September 30, 20162017 and December 31, 2015,2016, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement ($2.4(at September 30, 2017, $1.0 million excluding current maturities and $2.4 million including current maturities, and, at December 31, 2016, $2.1 million excluding current maturities and $3.5 million respectively, net of current maturities, and $3.8 million and $4.8 million, respectively, including current maturities). Sandpiper entered into this six-year agreement atAt the closing of the ESG acquisition in May 2013.2013, Sandpiper entered into this agreement, which has a six-year term. The capacity portion of this agreement is accounted for as a capital lease.
Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. OnWe have maintained a ratio of equity to total capitalization, including short-term borrowings, between 50 percent and 57 percent during the past three years. In 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$57.4 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. The issuance of equity resulted in our equity to total capitalization ratio representing 59% as of September 30, 2016.
As described below under “Short-term Borrowings,” we entered into the Credit Agreement and the Revolver with the Lenders onin October 8, 2015, which increased our borrowing capacity by $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into a long-termthe Prudential Shelf Agreement with Prudential for the potential private placement of the Prudential Shelf Notes as further described below under the heading “Shelf Agreement.Agreements.” In addition, we also entered into the MetLife and NYL Shelf Agreements, as described in further detail below, to have additional debt capital available to fund future growth capital expenditures.
For larger revenue-generating capital projects, to the extent feasible, we will seek to align, as much as feasible, any planned long-term debt or equity issuances with the earnings associatedissuance(s) with the commencement of long-term service for larger revenue-generating capital projects. Theand associated earnings. In addition, the exact timing of any long-term debt or equity issuancesissuance(s) will be based on market conditions.
Shelf Agreements
In October 2015, we entered into the Prudential Shelf Agreement, under which, through October 8, 2018, we may request that Prudential purchase up to $150.0 million of our Prudential Shelf Notes. The Prudential Shelf Notes have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.
In May 2016, Prudential confirmed and accepted our request that Prudential purchase $70.0 million of 3.25 percent Prudential Shelf Notes under the Prudential Shelf Agreement. We issued the Prudential Shelf Notes on April 21, 2017 and used the proceeds to reduce short-term borrowings under the Revolver, which had increased as a result of funding capital expenditures on a temporary basis.
The Prudential Shelf Agreement sets forth certain business covenants to which we are subject when any Prudential Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.
In March 2017, we entered into the MetLife Shelf Agreement and NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase. As of September 30, 2017, no unsecured notes have been issued under either the MetLife Shelf Agreement or the NYL Shelf Agreement.
Short-term Borrowings
Our outstanding short-term borrowings at September 30, 20162017 and December 31, 20152016 were $154.5$203.1 million and $173.4$209.9 million, respectively. The weighted average interest rates for our short-term borrowings were 1.491.96 percent and 1.091.49 percent, for the nine months ended September 30, 20162017 and 2015,2016, respectively.
We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of September 30, 2016,2017, we had four unsecured bank credit facilities with three financial institutions totaling $170.0$180.0 million in total available credit.
In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver with five participating Lenders. The terms of the Revolver are described in further detail below. We also had access to two credit facilities with a total of $40.0 million of available credit. The Revolver replaced these credit facilities when they expired on October 31, 2015. None of the unsecured bank lines of credit requires compensating balances. We are currently authorized by our Board of Directors to borrow up to $275.0 million of short-term borrowing.
The $150.0 million Revolver has a five-year term and is subject to the terms and conditions set forth in the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate
plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25% or less. Interest is payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We have the right, under certain circumstances, to extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. At September 30, 2016 and December 31, 2015, we had outstanding borrowings of $50.0 million and $35.0 million, respectively, under the Revolver.
Shelf Agreement
On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the termsNone of the Shelf Agreement, through October 8, 2018, we may request that Prudential purchase up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase.
On May 13, 2016, we submitted a request that Prudential purchase $70.0 million of 3.25 percent Shelf Notes under the Shelf Agreement. On May 20, 2016, Prudential accepted and confirmed our request. The proceeds received from the issuances of the Shelf Notes will be used to reduce short-term borrowings under the Company’s revolving credit facility,unsecured bank lines of credit and/or to fund capital expenditures. The closingrequires compensating balances. We are currently authorized by our Board of the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.
The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries,Directors to incur indebtedness, place or permit liens and encumbrances on anyup to $275.0 million of our property or the property of our subsidiaries.short-term borrowing.
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the nine months ended September 30, 20162017 and 2015:2016:
| | | | Nine Months Ended | | Nine Months Ended |
| | September 30, | | September 30, |
| | 2016 | | 2015 | | 2017 | | 2016 |
(in thousands) | | | | | | | | |
Net cash provided by (used in): | | | | | | | | |
Operating activities | | $ | 82,225 |
| | $ | 93,932 |
| | $ | 98,372 |
| | $ | 85,733 |
|
Investing activities | | (106,992 | ) | | (118,233 | ) | | (141,453 | ) | | (109,730 | ) |
Financing activities | | 23,448 |
| | 23,508 |
| | 42,289 |
| | 22,678 |
|
Net decrease in cash and cash equivalents | | (1,319 | ) | | (793 | ) | | (792 | ) | | (1,319 | ) |
Cash and cash equivalents—beginning of period | | 2,855 |
| | 4,574 |
| | 4,178 |
| | 2,855 |
|
Cash and cash equivalents—end of period | | $ | 1,536 |
| | $ | 3,781 |
| | $ | 3,386 |
| | $ | 1,536 |
|
Cash Flows Provided By Operating Activities
Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash adjustments for depreciation,items such as changes in deferred income taxes, depreciation and working capital. Changes in working capital are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.
During the nine months ended September 30, 20162017 and 2015,2016, net cash provided by operating activities was $82.2$98.4 million and $93.9$85.7 million, respectively, resulting in a decreasean increase in cash flows of $11.7$12.6 million. Significant operating activities generating the cash flows change were as follows:
Net income, adjusted for reconciling activities, increased cash flows by $15.4$17.9 million, due primarily to an increase in deferred income taxes as a result of the availability and utilization of bonus depreciation in the first nine months of 2016,2017, which resulted in a higher book-to-tax timing difference and higher non-cash adjustments for depreciation and amortization.
amortization related to increased investing activities.
Changes in net regulatory assets and liabilitiesincome taxes receivable decreased cash flows by $9.8$18.7 million, due primarily to changeslower tax refunds during the first nine months of 2017 compared to the same period in fuel costs collected through the various fuel cost recovery mechanisms.2016.
Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreasedincreased cash flows by $12.2$14.1 million, due primarily to higher revenues and the timing of the receipt of customer payments as well as increased operating expenses and the timing of payments to vendors.
Net cash flows from changes in other inventories decreased by approximately $6.1 million, due primarily to additional pipes and other construction inventory purchases, which increased the levels of our inventory.
Changes in propane, natural gasnet regulatory assets and materials inventories decreased netliabilities increased cash flows by approximately $5.3$4.3 million, due primarily to changes in GRIP and fuel costs collected through the various cost recovery mechanisms.
Changes in net prepaid expenses and other current assets, customer deposits and refunds, other assets and liabilities and accrued compensation increased cash flows by $1.2 million.
Cash Flows Used in Investing Activities
Net cash used in investing activities totaled $107.0$141.5 million and $118.2$109.7 million during the nine months ended September 30, 20162017 and 2015,2016, respectively, resulting in an increasea decrease in cash flows of $11.2$31.8 million. This was due primarilySignificant investing activities generating the cash flows change were as follows:
Cash paid for capital expenditures increased by $20.5 million to the $20.7$130.1 million net cash ($27.5 million cash paid, less $6.8 million of cash acquired)used for the Gatherco acquisitionfirst nine months of 2017, compared to $109.6 million for the same period in 2015. An increase2016.
Net cash of $11.7 million was used to acquire ARM and Chipola during the first nine months of 2017; there were no corresponding transactions in capital investments of $9.7 million partially offset this decrease.2016.
Cash Flows Provided byUsed in Financing Activities
Net cash provided byin financing activities totaled $23.4$42.3 million and $22.7 million during the nine months ended September 30, 2017 and 2016, respectively. The increase in net cash used in financing activities for the nine months ended September 30, 2017 resulted primarily from the following:
We received $69.8 million in net cash proceeds from the first nine monthsissuance of both 2016the Prudential Shelf Notes, and 2015. we paid $2.9 million more in scheduled long-term debt principal payments and capital lease obligations payments.
Net proceeds ofcash flows decreased by $57.3 million after deducting underwriting commissions and expenses, from proceeds related to the issuance of common stock during the third quarter of 2016, was used to pay down short-term debt. 2016.
Net cash provided by financing activities further increased as a resultrepayments under our line of an increase in a cash overdraftcredit arrangements of $2.5$3.8 million and an increase in short-term borrowing of $35.9 million, partially offset by common stock dividends of $13.0 million and $600,000 of stock issued for the Dividend Reinvestment Plan. During the nine months ended September 30, 2015, there were approximately $31.62017, compared to net repayments of $21.4 million for the same period in 2016, increased cash flows by $17.6 million. Change in cash overdrafts decreased cash flows by $5.5 million.
We paid $14.8 million in net additional borrowings, offset by common stockcash dividends of $11.7 million and $633,000 of stock issued for the Dividend Reinvestment Plan.nine months ended September 30, 2017, compared to $13.0 million for the nine months ended September 30, 2016.
Off-Balance Sheet Arrangements
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily Xeron and PESCO, whichPESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that the subsidiary defaults. Neither subsidiaryof default. PESCO has evernever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at September 30, 20162017 was $53.9$71.9 million, with the guarantees expiring on various dates through September 2017.2018.
We have issued letters of credit totaling $8.4$5.8 million related to the electric transmission services for FPU's northwest 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.June 2018. There have been no draws on these letters of credit as of September 30, 2016.2017. We do not anticipate that the letters of credit will be drawn upon by
the counterparties, and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Item 1, Financial Statements, Note 65, Other Commitments and Contingencies in the Condensed Consolidated Financial Statements.condensed consolidated financial statements.
Contractual Obligations
There has been no material change in the contractual obligations presented in our 20152016 Annual Report on Form 10-K, except for long-term debt, commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes long-term debt, commodity and forward contract obligations at September 30, 2016:2017:
| | | | Payments Due by Period | | Payments Due by Period |
| | Less than 1 year | | 1 - 3 years | | 3 - 5 years | | More than 5 years | | Total | | Less than 1 year | | 1 - 3 years | | 3 - 5 years | | More than 5 years | | Total |
(in thousands) | | | | | | | | | | | | | | | | | | | | |
Purchase obligations - Commodity (1) | | $ | 42,155 |
| | $ | 3,417 |
| | $ | — |
| | $ | — |
| | $ | 45,572 |
| |
Long-term debt (1) | | | $ | 10,698 |
| | $ | 24,226 |
| | $ | 40,700 |
| | $ | 135,800 |
| | $ | 211,424 |
|
Purchase obligations - Commodity (2) | | | 47,069 |
| | 1,693 |
| | — |
| | — |
| | 48,762 |
|
Total | | | $ | 57,767 |
| | $ | 25,919 |
| | $ | 40,700 |
| | $ | 135,800 |
| | $ | 260,186 |
|
| |
(1) | Excludes capital lease obligation, debt issuance costs and unamortized debt discount of $1,960. |
| |
(2) | In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate. |
Rates and Regulatory Matters
Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At September 30, 2016,2017, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 43, Rates and Other Regulatory Activities, to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1, Summary of Accounting Policies, to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
Market risk represents the potential loss arising from adverse changes in market rates and prices. INTEREST RATE RISK
Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes and secured debt. All of our long-term debt, excluding a capital lease obligation, is fixed-rate debt and was not entered into for trading purposes. The carrying value of our long-term debt, including current maturities, but excluding a capital lease obligation, was $151.8 million at September 30, 20162017, as compared to a fair valueconsists of $173.5fixed-rate Senior Notes and $8.0 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, with adjustments for duration, optionality, credit risk, and risk profile.of fixed-rate secured debt. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing,borrowings based in part on the fluctuation in interest rates. Additional information about our long-term debt is disclosed in Note 13, Long-term Debt, in the condensed consolidated financial statements.
COMMODITY PRICE RISK
Regulated Energy Segment
We have entered into agreements with various wholesale suppliers to purchase natural gas and electricity for resale to our customers. Our propaneregulated energy distribution business isbusinesses that sell natural gas or electricity to end-use customers have fuel cost recovery mechanisms authorized by the PSCs that allow us to periodically adjust fuel rates to reflect changes in the wholesale cost of natural gas and electricity and to ensure that we recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.
Unregulated Energy Segment
Sharp and Flo-gas are exposed to marketcommodity price risk as a result of the competitive nature of retail pricing offered to our customers. In order to mitigate this risk, we utilize propane storage activities and entering into fixed priceforward contracts for supply.
We can store up to approximately 6.86.2 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause
the value of stored propane to decline.decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the impactrisk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows theour propane distribution operation to hedge itsenter into fair value hedges, cash flows hedges or other economic hedges of our inventory.
In 2016, PESCO entered into a SCO supplier agreement with Columbia GasAspire Energy is exposed to providecommodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas supply for Columbia Gaspurchases and sales and have to service one of its local distribution customer tranches. PESCO also assumed the obligation to storesecure natural gas inventoryfrom alternative sources at higher spot prices. In order to satisfy its obligations under the SCO supplier agreement,mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers with which terminates on March 31, 2017. In conjunction with the SCO supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016to contract in order to protect itsfulfill our natural gas inventory against market price fluctuations.purchase requirements.
Our propane wholesale marketing operationPESCO is a party to propane and crude oil futures and forward contracts, with various third parties, which require that the propane wholesale marketing operation purchase or sell natural gas liquids or crude oilfutures contracts. These contracts provide PESCO with the right to purchase natural gas at a fixed price at fixed future dates. AtUpon expiration, the contracts are typicallycan be settled financially without taking physical delivery of propanenatural gas, or crude oil. The propane wholesale marketing operation also enters into futures contracts that are traded on the Intercontinental Exchange, Inc. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane or crude oil.PESCO can procure natural gas for its customers.
The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing businessPESCO is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids and natural gas deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes dollarvolumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets, and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. As of
WSeptember 30, 2016HOLESALE , there were no outstanding contracts.CREDIT RISK
We have entered into agreementsThe Risk Management Committee reviews credit risks associated with various supplierscounterparties to purchase natural gas, electricity and propane for resalecommodity derivative contracts prior to our customers. Purchases under thesesuch contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis.
being approved.
AtAdditional information about our derivative instruments is disclosed in Note 11, September 30, 2016Derivative Instruments, and December 31, 2015, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:condensed consolidated financial statements.
|
| | | | | | | | |
| | | | |
(in thousands) | | September 30, 2016 | | December 31, 2015 |
Mark-to-market energy assets, including call options, swap agreements and futures | | $ | 477 |
| | $ | 153 |
|
Mark-to-market energy liabilities, including swap agreements and futures | | $ | 29 |
| | $ | 433 |
|
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2016.2017. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2016.2017.
Changes in Internal Control over Financial Reporting
During the quarter ended September 30, 2016,2017, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.
PART II—OTHER INFORMATION
Item 1. Legal Proceedings
As disclosed in Note 65, Other Commitments and Contingencies, of the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.
| |
Item 1A. | Item 1A. Risk Factors |
Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2015,2016, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating Chesapeake Utilities, our business and the forward-looking statements contained in this Quarterly Report on Form 10-Q. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial, also may affect Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition and results of operations.
| |
Item 2. | Unregistered Sales of Equity Securities and Use of Proceeds |
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
|
| | | | | | | | | | | | | |
| | Total Number of Shares | | Average Price Paid | | Total Number of Shares Purchased as Part of Publicly Announced Plans | | Maximum Number of Shares That May Yet Be Purchased Under the Plans |
Period | | Purchased | | per Share | | or Programs (2) | | or Programs (2) |
July 1, 2016 through July 30, 2016 (1) | | 366 |
| | $ | 66.35 |
| | — |
| | — |
|
August 1, 2016 through August 31, 2016
| | — |
| | $ | — |
| | — |
| | — |
|
September 1, 2016 through September 30, 2016
| | — |
| | $ | — |
| | — |
| | — |
|
Total | | 366 |
| | $ | 66.35 |
| | — |
| | — |
|
|
| | | | | | | | | | | | | |
| | Total Number of Shares | | Average Price Paid | | Total Number of Shares Purchased as Part of Publicly Announced Plans | | Maximum Number of Shares That May Yet Be Purchased Under the Plans |
Period | | Purchased | | per Share | | or Programs (2) | | or Programs (2) |
July 1, 2017 through July 31, 2017 (1) | | 387 |
| | $ | 75.75 |
| | — |
| | — |
|
August 1, 2017 through August 31, 2017
| | — |
| | $ | — |
| | — |
| | — |
|
September 1, 2017 through September 30, 2017
| | — |
| | $ | — |
| | — |
| | — |
|
Total | | 387 |
| | $ | 75.75 |
| | — |
| | — |
|
| |
(1) | Chesapeake Utilities purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 20152016. During the quarter ended September 30, 2016, 3662017, 387 shares were purchased through the reinvestment of dividends on deferred stock units. |
| |
(2) | Except for the purposes described in Footnote (1), Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares. |
| |
Item 3. | Defaults upon Senior Securities |
Item 3. Defaults upon Senior Securities
None.
Item 5. Other Information
None.
|
| | |
| | |
1.1 | | Underwriting Agreement entered into by Chesapeake Utilities Corporation and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, Janney Montgomery Scott LLC., Robert W. Baird & Co., Incorporated, J.J.B. Hilliard, W.L. Lyons, LLC, Ladenburg Thalmann & Co. Inc., U.S. Capital Advisors LLC and BB&T Securities, LLC on September 22, 2016, relating to the sale and issuance of 835,207 shares of the Company’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’s current report on Form 8-K, filed on September 28, 2016, File No. 001-11590. |
| | |
3.3 | | Second Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective November 2, 2016, is filed herewith. |
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31.1 | | |
| | |
31.2 | | |
| | |
32.1 | | |
| | |
32.2 | | |
| | |
101.INS* | | XBRL Instance Document. |
| |
101.SCH* | | XBRL Taxonomy Extension Schema Document. |
| |
101.CAL* | | XBRL Taxonomy Extension Calculation Linkbase Document. |
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101.DEF* | | XBRL Taxonomy Extension Definition Linkbase Document. |
| |
101.LAB* | | XBRL Taxonomy Extension Label Linkbase Document. |
| |
101.PRE* | | XBRL Taxonomy Extension Presentation Linkbase Document. |
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
|
|
CHESAPEAKE UTILITIES CORPORATION |
|
/S/ BETH W. COOPER |
Beth W. Cooper Senior Vice President and Chief Financial Officer |
Date: November 3, 20169, 2017