Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP | cpk6302017ex-322.htm |
| EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP | cpk6302017ex-321.htm |
| EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP | cpk6302017ex-312.htm |
| EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP | cpk6302017ex-311.htm |
| EX-10.1 - EXHIBIT 10.1 - CHESAPEAKE UTILITIES CORP | cpk6302017ex-101.htm |
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-Q | ||
x | QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the quarterly period ended: June 30, 2017
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-11590
CHESAPEAKE UTILITIES CORPORATION (Exact name of registrant as specified in its charter) | ||
Delaware | 51-0064146 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Common Stock, par value $0.4867 — 16,344,442 shares outstanding as of July 31, 2017.
Table of Contents
ITEM 1. | ||
ITEM 2. | ||
ITEM 3. | ||
ITEM 4. | ||
ITEM 1. | ||
ITEM 1A. | ||
ITEM 2. | ||
ITEM 3. | ||
ITEM 5. | ||
ITEM 6. | ||
GLOSSARY OF DEFINITIONS
ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities
CDD: Cooling 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 above 65 degrees Fahrenheit
Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, 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
CIAC: Contributions from customers that are used to construct facilities
CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative
CHP: Combined heat and power plant
Columbia Gas: Columbia Gas of Ohio, an unaffiliated local distribution company based in Ohio
Company: Chesapeake Utilities Corporation, and its direct and indirect subsidiaries, as appropriate in the context of the disclosure
Credit Agreement: The Credit Agreement dated October 8, 2015, among Chesapeake Utilities and the Lenders related to the Revolver
Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers
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
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
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, a natural gas pipeline replacement program in Florida pursuant to which we collect a surcharge from certain of our customers to recover capital and other program-related costs associated with the replacement of qualifying distribution mains and services
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 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
MWH: Megawatt hour, which is a unit of measurement for electricity
NYL: New York Life 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 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, a tariff associated with Eastern Shore's firm transportation service that enables Eastern Shore to forgo 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., Chesapeake Utilities' wholly-owned Florida intrastate pipeline subsidiary
PESCO: Peninsula Energy Services Company, Inc., Chesapeake Utilities' wholly-owned natural gas marketing subsidiary
PNC: PNC Bank, National Association, the administrative agent and primary lender for our Revolver
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Prudential Shelf Agreement
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 date of issuance
Prudential Shelf Notes: Unsecured senior promissory notes that we may request Prudential to purchase under the Prudential Shelf Agreement
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
Rayonier: Rayonier Performance Fibers, LLC, the company that owns the property on which Eight Flags' CHP plant is located and that supplies electricity to FPU
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., Chesapeake Utilities' wholly-owned subsidiary, which provides a tariff-based distribution service to customers in Worcester County, Maryland
Sanford Group: FPU and other responsible parties involved with the Sanford MGP site
SEC: Securities and Exchange Commission
Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
Sharp: Sharp Energy, Inc., Chesapeake Utilities' wholly-owned propane distribution subsidiary
SICP: 2013 Stock and Incentive Compensation Plan
TETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline
Xeron: Xeron, Inc., an 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 | Six Months Ended | ||||||||||||||||
June 30, | June 30, | ||||||||||||||||
2017 | 2016 | 2017 | 2016 | ||||||||||||||
(in thousands, except shares and per share data) | |||||||||||||||||
Operating Revenues | |||||||||||||||||
Regulated Energy | $ | 70,996 | $ | 67,395 | $ | 168,650 | $ | 156,611 | |||||||||
Unregulated Energy and other | 54,088 | 34,947 | 141,594 | 92,027 | |||||||||||||
Total Operating Revenues | 125,084 | 102,342 | 310,244 | 248,638 | |||||||||||||
Operating Expenses | |||||||||||||||||
Regulated Energy cost of sales | 24,167 | 21,635 | 64,411 | 56,540 | |||||||||||||
Unregulated Energy and other cost of sales | 40,505 | 22,934 | 101,260 | 56,958 | |||||||||||||
Operations | 30,408 | 28,087 | 63,321 | 55,246 | |||||||||||||
Maintenance | 3,403 | 2,904 | 6,634 | 5,383 | |||||||||||||
Gain from a settlement | (130 | ) | (130 | ) | (130 | ) | (130 | ) | |||||||||
Depreciation and amortization | 9,094 | 7,780 | 17,906 | 15,283 | |||||||||||||
Other taxes | 3,971 | 3,390 | 8,501 | 7,236 | |||||||||||||
Total Operating Expenses | 111,418 | 86,600 | 261,903 | 196,516 | |||||||||||||
Operating Income | 13,666 | 15,742 | 48,341 | 52,122 | |||||||||||||
Other expense, net | (607 | ) | (8 | ) | (884 | ) | (42 | ) | |||||||||
Interest charges | 3,073 | 2,624 | 5,811 | 5,274 | |||||||||||||
Income Before Income Taxes | 9,986 | 13,110 | 41,646 | 46,806 | |||||||||||||
Income taxes | 3,940 | 5,081 | 16,456 | 18,410 | |||||||||||||
Net Income | $ | 6,046 | $ | 8,029 | $ | 25,190 | $ | 28,396 | |||||||||
Weighted Average Common Shares Outstanding: | |||||||||||||||||
Basic | 16,340,665 | 15,315,020 | 16,329,009 | 15,300,931 | |||||||||||||
Diluted | 16,382,207 | 15,352,702 | 16,373,038 | 15,342,287 | |||||||||||||
Earnings Per Share of Common Stock: | |||||||||||||||||
Basic | $ | 0.37 | $ | 0.52 | $ | 1.54 | $ | 1.86 | |||||||||
Diluted | $ | 0.37 | $ | 0.52 | $ | 1.54 | $ | 1.85 | |||||||||
Cash Dividends Declared Per Share of Common Stock | $ | 0.3250 | $ | 0.3050 | $ | 0.6300 | $ | 0.5925 | |||||||||
The accompanying notes are an integral part of these financial statements.
- 1
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(in thousands) | ||||||||||||||||
Net Income | $ | 6,046 | $ | 8,029 | $ | 25,190 | $ | 28,396 | ||||||||
Other Comprehensive (Loss) Income, net of tax: | ||||||||||||||||
Employee Benefits, net of tax: | ||||||||||||||||
Amortization of prior service cost, net of tax of $(8), $(8), $(16) and $(16), respectively | (12 | ) | (12 | ) | (23 | ) | (24 | ) | ||||||||
Net gain, net of tax of $69, $67, $145 and $133, respectively | 101 | 99 | 194 | 200 | ||||||||||||
Cash Flow Hedges, net of tax: | ||||||||||||||||
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(554), $313, $(362) and $322, respectively | (875 | ) | 496 | (537 | ) | 496 | ||||||||||
Total Other Comprehensive (Loss) Income | (786 | ) | 583 | (366 | ) | 672 | ||||||||||
Comprehensive Income | $ | 5,260 | $ | 8,612 | $ | 24,824 | $ | 29,068 | ||||||||
The accompanying notes are an integral part of these financial statements.
- 2
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Assets | June 30, 2017 | December 31, 2016 | ||||||
(in thousands, except shares and per share data) | ||||||||
Property, Plant and Equipment | ||||||||
Regulated Energy | $ | 1,038,929 | $ | 957,681 | ||||
Unregulated Energy | 202,707 | 196,800 | ||||||
Other businesses and eliminations | 25,623 | 21,114 | ||||||
Total property, plant and equipment | 1,267,259 | 1,175,595 | ||||||
Less: Accumulated depreciation and amortization | (260,428 | ) | (245,207 | ) | ||||
Plus: Construction work in progress | 44,556 | 56,276 | ||||||
Net property, plant and equipment | 1,051,387 | 986,664 | ||||||
Current Assets | ||||||||
Cash and cash equivalents | 2,419 | 4,178 | ||||||
Accounts receivable (less allowance for uncollectible accounts of $862 and $909, respectively) | 41,113 | 62,803 | ||||||
Accrued revenue | 11,812 | 16,986 | ||||||
Propane inventory, at average cost | 4,649 | 6,457 | ||||||
Other inventory, at average cost | 9,996 | 4,576 | ||||||
Regulatory assets | 7,167 | 7,694 | ||||||
Storage gas prepayments | 4,415 | 5,484 | ||||||
Income taxes receivable | 14,409 | 22,888 | ||||||
Prepaid expenses | 3,939 | 6,792 | ||||||
Mark-to-market energy assets | 229 | 823 | ||||||
Other current assets | 2,287 | 2,470 | ||||||
Total current assets | 102,435 | 141,151 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 15,070 | 15,070 | ||||||
Other intangible assets, net | 1,664 | 1,843 | ||||||
Investments, at fair value | 5,952 | 4,902 | ||||||
Regulatory assets | 76,128 | 76,803 | ||||||
Receivables and other deferred charges | 4,352 | 2,786 | ||||||
Total deferred charges and other assets | 103,166 | 101,404 | ||||||
Total Assets | $ | 1,256,988 | $ | 1,229,219 | ||||
The accompanying notes are an integral part of these financial statements.
- 3
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Capitalization and Liabilities | June 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) | 7,955 | 7,935 | ||||||
Additional paid-in capital | 252,071 | 250,967 | ||||||
Retained earnings | 206,896 | 192,062 | ||||||
Accumulated other comprehensive loss | (5,244 | ) | (4,878 | ) | ||||
Deferred compensation obligation | 3,336 | 2,416 | ||||||
Treasury stock | (3,336 | ) | (2,416 | ) | ||||
Total stockholders’ equity | 461,678 | 446,086 | ||||||
Long-term debt, net of current maturities | 201,590 | 136,954 | ||||||
Total capitalization | 663,268 | 583,040 | ||||||
Current Liabilities | ||||||||
Current portion of long-term debt | 12,124 | 12,099 | ||||||
Short-term borrowing | 145,591 | 209,871 | ||||||
Accounts payable | 52,101 | 56,935 | ||||||
Customer deposits and refunds | 30,725 | 29,238 | ||||||
Accrued interest | 1,637 | 1,312 | ||||||
Dividends payable | 5,312 | 4,973 | ||||||
Accrued compensation | 6,683 | 10,496 | ||||||
Regulatory liabilities | 5,609 | 1,291 | ||||||
Mark-to-market energy liabilities | 188 | 773 | ||||||
Other accrued liabilities | 12,084 | 7,063 | ||||||
Total current liabilities | 272,054 | 334,051 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes | 234,716 | 222,894 | ||||||
Regulatory liabilities | 42,427 | 43,064 | ||||||
Environmental liabilities | 8,457 | 8,592 | ||||||
Other pension and benefit costs | 31,920 | 32,828 | ||||||
Deferred investment tax credits and other liabilities | 4,146 | 4,750 | ||||||
Total deferred credits and other liabilities | 321,666 | 312,128 | ||||||
Environmental and other commitments and contingencies (Note 4 and 5) | ||||||||
Total Capitalization and Liabilities | $ | 1,256,988 | $ | 1,229,219 | ||||
The accompanying notes are an integral part of these financial statements.
- 4
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
Six Months Ended | ||||||||
June 30, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Operating Activities | ||||||||
Net income | $ | 25,190 | $ | 28,396 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 17,906 | 15,283 | ||||||
Depreciation and accretion included in other costs | 3,939 | 3,436 | ||||||
Deferred income taxes | 12,034 | 6,162 | ||||||
Realized loss on commodity contracts/sale of assets/investments | 2,223 | 664 | ||||||
Unrealized loss/(gain) on investments/commodity contracts | 184 | (42 | ) | |||||
Employee benefits and compensation | 819 | 760 | ||||||
Share-based compensation | 812 | 1,264 | ||||||
Other, net | (17 | ) | 24 | |||||
Changes in assets and liabilities: | ||||||||
Accounts receivable and accrued revenue | 26,862 | 2,264 | ||||||
Propane inventory, storage gas and other inventory | (2,543 | ) | 663 | |||||
Regulatory assets/liabilities, net | 4,255 | 519 | ||||||
Prepaid expenses and other current assets | 2,129 | 2,878 | ||||||
Accounts payable and other accrued liabilities | (280 | ) | (561 | ) | ||||
Income taxes receivable | 8,500 | 20,680 | ||||||
Customer deposits and refunds | 1,487 | 399 | ||||||
Accrued compensation | (3,876 | ) | (3,340 | ) | ||||
Other assets and liabilities, net | (3,254 | ) | (1,786 | ) | ||||
Net cash provided by operating activities | 96,370 | 77,663 | ||||||
Investing Activities | ||||||||
Property, plant and equipment expenditures | (88,627 | ) | (72,783 | ) | ||||
Proceeds from sales of assets | 185 | 89 | ||||||
Environmental expenditures | (135 | ) | (177 | ) | ||||
Net cash used in investing activities | (88,577 | ) | (72,871 | ) | ||||
Financing Activities | ||||||||
Common stock dividends | (9,636 | ) | (8,453 | ) | ||||
Issuance of stock for Dividend Reinvestment Plan | 421 | 429 | ||||||
Tax withholding payments related to net settled stock compensation | (692 | ) | (770 | ) | ||||
Change in cash overdrafts due to outstanding checks | (2,370 | ) | 1,473 | |||||
Net (repayment) borrowing under line of credit agreements | (61,910 | ) | 5,166 | |||||
Proceeds from issuance of long-term debt | 69,800 | — | ||||||
Repayment of long-term debt and capital lease obligation | (5,165 | ) | (2,226 | ) | ||||
Net cash used by financing activities | (9,552 | ) | (4,381 | ) | ||||
Net (Decrease) Increase in Cash and Cash Equivalents | (1,759 | ) | 411 | |||||
Cash and Cash Equivalents—Beginning of Period | 4,178 | 2,855 | ||||||
Cash and Cash Equivalents—End of Period | $ | 2,419 | $ | 3,266 | ||||
The accompanying notes are an integral part of these financial statements.
- 5
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
Common Stock (1) | ||||||||||||||||||||||||||||||
(in thousands, except shares and per share data) | 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, 2015 | 15,270,659 | $ | 7,432 | $ | 190,311 | $ | 166,235 | $ | (5,840 | ) | $ | 1,883 | $ | (1,883 | ) | $ | 358,138 | |||||||||||||
Net income | — | — | — | 44,675 | — | — | — | 44,675 | ||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 962 | — | — | 962 | ||||||||||||||||||||||
Dividend declared ($1.2025 per share) | — | — | — | (18,848 | ) | — | — | — | (18,848 | ) | ||||||||||||||||||||
Retirement savings plan and dividend reinvestment plan | 36,253 | 17 | 2,225 | — | — | — | — | 2,242 | ||||||||||||||||||||||
Stock issuance (3) | 960,488 | 467 | 56,893 | — | — | — | — | 57,360 | ||||||||||||||||||||||
Share-based compensation and tax benefit (4) (5) | 36,099 | 19 | 1,538 | — | — | — | — | 1,557 | ||||||||||||||||||||||
Treasury stock activities | — | — | — | — | — | 533 | (533 | ) | — | |||||||||||||||||||||
Balance at December 31, 2016 | 16,303,499 | 7,935 | 250,967 | 192,062 | (4,878 | ) | 2,416 | (2,416 | ) | 446,086 | ||||||||||||||||||||
Net income | — | — | — | 25,190 | — | — | — | 25,190 | ||||||||||||||||||||||
Other comprehensive loss | — | — | — | — | (366 | ) | — | — | (366 | ) | ||||||||||||||||||||
Dividend declared ($0.6300 per share) | — | — | — | (10,356 | ) | — | — | — | (10,356 | ) | ||||||||||||||||||||
Dividend reinvestment plan | 10,771 | 5 | 731 | — | — | — | — | 736 | ||||||||||||||||||||||
Share-based compensation and tax benefit (4) (5) | 30,172 | 15 | 373 | — | — | — | — | 388 | ||||||||||||||||||||||
Treasury stock activities | — | — | — | — | — | 920 | (920 | ) | — | |||||||||||||||||||||
Balance at June 30, 2017 | 16,344,442 | $ | 7,955 | $ | 252,071 | $ | 206,896 | $ | (5,244 | ) | $ | 3,336 | $ | (3,336 | ) | $ | 461,678 | |||||||||||||
(1) | 2,000,000 shares of preferred stock at $0.01 par value has been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity. |
(2) | Includes 90,201 and 76,745 shares at June 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 $57.4 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 six months ended June 30, 2017, and for the year ended December 31, 2016, we withheld 10,269 and 12,031 shares, respectively, for taxes. |
The accompanying notes are an integral part of these financial statements.
- 6
NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
1. Summary of Accounting Policies
Basis of Presentation
References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.
The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 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 statement of cash flows for the six months ended June 30, 2016 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
Subsequent Event
On June 20, 2017, PESCO entered into an agreement to purchase certain operating assets of ARM Energy Management. These assets are used to provide natural gas supply and supply management services to commercial and industrial customers in Western Pennsylvania. The transaction was consummated on August 1, 2017 and will not have a material impact on our financial results.
FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
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. We adopted ASU 2015-11 on January 1, 2017 on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations.
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 interim and annual financial statements issued beginning January 1, 2018.
We are in the process of evaluating our revenue sources and assessing the impact on our financial position, results of operations and cash flows. We expect this evaluation to be completed in the third 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 and make the necessary system and process changes. In the third quarter of 2017, we will provide additional training to our employees and implement 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.
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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 quarterly report on Form 10-Q for the third quarter of 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 third and fourth quarters 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 guidance will be applied using the modified retrospective transition method for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements.
Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We are assessing the impact of the adoption of this ASU on our statements of cash flows.
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 are evaluating the effect of this ASU on our future financial position and 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. We are evaluating the effect of this update on our future financial position and results of operations.
Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scope of Modification Accounting, 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 are evaluating the effect of this update on our future financial position and results of operations.
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2. | Calculation of Earnings Per Share |
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(in thousands, except shares and per share data) | ||||||||||||||||
Calculation of Basic Earnings Per Share: | ||||||||||||||||
Net Income | $ | 6,046 | $ | 8,029 | $ | 25,190 | $ | 28,396 | ||||||||
Weighted average shares outstanding | 16,340,665 | 15,315,020 | 16,329,009 | 15,300,931 | ||||||||||||
Basic Earnings Per Share | $ | 0.37 | $ | 0.52 | $ | 1.54 | $ | 1.86 | ||||||||
Calculation of Diluted Earnings Per Share: | ||||||||||||||||
Reconciliation of Numerator: | ||||||||||||||||
Net Income | $ | 6,046 | $ | 8,029 | 25,190 | 28,396 | ||||||||||
Reconciliation of Denominator: | ||||||||||||||||
Weighted shares outstanding—Basic | 16,340,665 | 15,315,020 | 16,329,009 | 15,300,931 | ||||||||||||
Effect of dilutive securities—Share-based compensation | 41,542 | 37,682 | 44,029 | 41,356 | ||||||||||||
Adjusted denominator—Diluted | 16,382,207 | 15,352,702 | 16,373,038 | 15,342,287 | ||||||||||||
Diluted Earnings Per Share | $ | 0.37 | $ | 0.52 | $ | 1.54 | $ | 1.85 | ||||||||
3. | Rates and Other Regulatory Activities |
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.
Delaware
Rate Case Filing: In December 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. The Delaware Division, Delaware PSC Staff, the Division of the Public Advocate and other intervenors met and reached a settlement agreement in November 2016. The terms of the settlement agreement included an annual increase of $2.25 million in base rates. The order became final in December 2016, and the new rates became effective January 1, 2017. Amounts collected through interim rates in excess of the respective portion of the $2.25 million increase through December 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.
Florida
Cost Recovery for the Electric Interconnect Project: In September 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 would enable FPU's electric division to negotiate a new power purchase agreement to mitigate fuel costs for its Northeast division. FPU's proposal was approved by the Florida PSC at its Agenda Conference held in December 2015. In January 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. The Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs and oral arguments. As a result, FPU will exclude the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause filing and plans to include this project for recovery in a limited proceeding.
Surcharge Associated with Modernization of Electric Distribution System Project: In February 2017, FPU’s electric 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 ("Modernization of Electric Distribution System Project"). We requested approval to invest approximately $59.8 million over a five-year period associated with the Modernization of Electric Distribution System
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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 a temporary surcharge. In April 2017, FPU voluntarily withdrew its petition 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 Florida PSC requesting inclusion of certain capital projects in its rate base, and to adjust its base rates accordingly. These projects are designed to significantly improve the stability and outage response times for FPU's electric distribution system and potentially enable it to mitigate fuel costs for its electric customers through the Florida Power & Light Company interconnect project.
Eastern Shore
White Oak Mainline Expansion Project: In November 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware ("White Oak Mainline Project"). Eastern Shore proposed to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and increase compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. In November 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route and shortened the total miles of the proposed pipeline to 5.4 miles.
In July 2016, the FERC authorized Eastern Shore to construct and operate the proposed White Oak Mainline Project. As of the end of March 2017, the entire project was placed into service. The total cost to complete the project was approximately $41.0 million.
System Reliability Project: In May 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project. In July 2016, the FERC granted Eastern Shore’s pre-determination of rolled-in rate treatment absent any significant change in circumstances.
In September 2016, the FERC granted approval to start construction on all phases of the project. As of June 2017, the entire project was placed into service. The cost of the project was approximately $38.0 million. We will begin 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.
2017 Expansion Project: In May 2016, Eastern Shore submitted a request to the FERC to initiate the pre-filing review procedures for Eastern Shore's 2017 expansion project (the “2017 Expansion Project”). The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional 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 certificate of public convenience and necessity seeking authorization to construct the expansion facilities. Six of Eastern Shore's existing customers timely intervened to become parties. In February 2017, Eastern Shore submitted responses to the FERC staff's data requests.
In May 2017, the FERC staff issued the environmental assessment and set forth 22 environmental conditions with which Eastern Shore must comply. The FERC provided a 30-day comment period, which expired in June 2017. Comments were timely submitted by four relevant state and federal agencies and two private parties. Eastern Shore submitted responses to all comments.
In June 2017 and July 2017, the FERC issued requests for additional information related to a wetland area at the Jennersville Loop in Chester County, Pennsylvania. Eastern Shore submitted responses to both requests. The estimated cost of the 2017 Expansion Project is approximately $98.6 million.
2017 Rate Case Filing: 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 a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak
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Mainline Expansion project, which benefits a single customer. Eastern Shore is also proposing to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. The FERC issued a notice of the filing in January 2017, and the comment period ended in February 2017. Fourteen parties intervened in the proceeding with six of those parties filing protests to various aspects of the filing. New rates were proposed to be effective on March 1, 2017; however, the FERC issued an order suspending the tariff rates for the usual five-month period. Eastern Shore has filed the requisite notice with the FERC to implement interim rates effective August 1, 2017.
Eastern Shore has participated in several settlement conferences, in which the FERC staff has reviewed its proposals, and customers and interested parties have presented and discussed their positions. Another settlement conference is scheduled for August 30 and 31, 2017.
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 discussing with the MDE another former MGP site located in Cambridge, Maryland.
As of June 30, 2017, we had approximately $9.8 million in environmental liabilities, related 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 its MGP sites. Approximately $10.8 million has been recovered as of June 30, 2017, leaving approximately $3.2 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.
West Palm Beach, Florida
Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, on which FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. In January 2016, FDEP conducted a facility inspection and found no problems or deficiencies.
We expect that similar remedial actions will ultimately be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of June 30, 2017, 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-
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approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed and paid by FPU in 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 June 30, 2017, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine to a reasonable degree of certainty whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided for in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid pursuant to the Third Participation Agreement. No such claims have been made as of June 30, 2017.
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. In September 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 from testing conducted in April 2017 indicated that natural attenuation default criteria were met at all but two wells, and were submitted in a letter report to FDEP in June 2017. FDEP issued a comment letter dated June 15, 2017 requesting additional delineation of the plume in the southwest corner. We plan to install an additional well at the southwest corner of the property and to continue monitoring groundwater quality while operating the bio-sparge system.
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.
Seaford, Delaware
In December 2013, the DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that required further investigation. In September 2015, DNREC approved our application to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, which resulted in DNREC requesting additional investigative work be performed prior to approval of potential remedial actions. In December 2016, additional on-site wells were installed, developed and sampled pursuant to a September 2016 request from DNREC. The results of the sampling event and proposed future activities were submitted to DNREC in April 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.
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.
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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. 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 agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 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 2.9 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 2.9 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 either ratio is not met by FPU, it has 30 days to cure the default or, provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2017, FPU was in compliance with all of the requirements of its fuel supply contracts.
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 to Rayonier pursuant to a separate 20-year contract. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.
Corporate Guarantees
We have issued corporate guarantees to certain of our subsidiaries' vendors, the largest of which is PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at June 30, 2017 was approximately $57.2 million, with the guarantees expiring on various dates through June 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 13, Long-Term Debt, for further details).
Letters of Credit
As of June 30, 2017, we have issued letters of credit totaling approximately $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
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expiration dates through June 2018. There have been no draws on these letters of credit as of June 30, 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.
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.
6. | Segment Information |
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations are 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 as well as natural gas marketing, gathering, processing, transportation and supply. These operations are unregulated as to their rates and services. Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. Through March 31, 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017. Lastly, this segment also includes other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. |
Other operations are presented as “Other businesses and eliminations,” which consist 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.
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The following table presents financial information about our reportable segments:
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(in thousands) | ||||||||||||||||
Operating Revenues, Unaffiliated Customers | ||||||||||||||||
Regulated Energy segment | $ | 68,815 | $ | 66,590 | $ | 165,261 | $ | 155,483 | ||||||||
Unregulated Energy segment and other businesses | 56,269 | 35,752 | 144,983 | 93,154 | ||||||||||||
Total operating revenues, unaffiliated customers | $ | 125,084 | $ | 102,342 | $ | 310,244 | $ | 248,637 | ||||||||
Intersegment Revenues (1) | ||||||||||||||||
Regulated Energy segment | $ | 2,181 | $ | 805 | $ | 3,389 | $ | 1,128 | ||||||||
Unregulated Energy segment | 6,780 | 1,052 | 10,791 | 1,165 | ||||||||||||
Other businesses | 159 | 240 | 387 | 466 | ||||||||||||
Total intersegment revenues | $ | 9,120 | $ | 2,097 | $ | 14,567 | $ | 2,759 | ||||||||
Operating Income | ||||||||||||||||
Regulated Energy segment | $ | 13,730 | $ | 15,226 | $ | 36,747 | $ | 39,545 | ||||||||
Unregulated Energy segment | (38 | ) | 412 | 11,492 | 12,347 | |||||||||||
Other businesses and eliminations | (26 | ) | 104 | 102 | 230 | |||||||||||
Total operating income | 13,666 | 15,742 | 48,341 | 52,122 | ||||||||||||
Other expense, net | (607 | ) | (8 | ) | (884 | ) | (42 | ) | ||||||||
Interest | 3,073 | 2,624 | 5,811 | 5,274 | ||||||||||||
Income before Income Taxes | 9,986 | 13,110 | 41,646 | 46,806 | ||||||||||||
Income taxes | 3,940 | 5,081 | 16,456 | 18,410 | ||||||||||||
Net Income | $ | 6,046 | $ | 8,029 | $ | 25,190 | $ | 28,396 | ||||||||
(1) | All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. |
(in thousands) | June 30, 2017 | December 31, 2016 | ||||||
Identifiable Assets | ||||||||
Regulated Energy segment | $ | 1,025,745 | $ | 986,752 | ||||
Unregulated Energy segment | 202,730 | 226,368 | ||||||
Other businesses and eliminations | 28,513 | 16,099 | ||||||
Total identifiable assets | $ | 1,256,988 | $ | 1,229,219 | ||||
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7. | Stockholder's Equity |
Preferred Stock
We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of June 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 price per 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 comprehensive income (loss).
The following tables present the changes in the balance of accumulated other comprehensive loss for the six months ended June 30, 2017 and 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, 2016 | $ | (5,360 | ) | $ | 482 | $ | (4,878 | ) | ||||
Other comprehensive (loss)/income before reclassifications | (9 | ) | 837 | 828 | ||||||||
Amounts reclassified from accumulated other comprehensive (loss)/income | 180 | (1,374 | ) | (1,194 | ) | |||||||
Net current-period other comprehensive (loss)/income | 171 | (537 | ) | (366 | ) | |||||||
As of June 30, 2017 | $ | (5,189 | ) | $ | (55 | ) | $ | (5,244 | ) | |||
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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 | — | 525 | 525 | |||||||||
Amounts reclassified from accumulated other comprehensive loss | 176 | (29 | ) | 147 | ||||||||
Net prior-period other comprehensive income | 176 | 496 | 672 | |||||||||
As of June 30, 2016 | $ | (5,404 | ) | $ | 236 | $ | (5,168 | ) | ||||
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2017 and 2016. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
Three Months Ended | Six Months Ended | |||||||||||||||
June 30, | June 30, | |||||||||||||||
2017 | 2016 | 2017 | 2016 | |||||||||||||
(in thousands) | ||||||||||||||||
Amortization of defined benefit pension and postretirement plan items: | ||||||||||||||||
Prior service credit (1) | $ | 20 | $ | 20 | $ | 39 | $ | 40 | ||||||||
Net loss(1) | (170 | ) | (166 | ) | (339 | ) | (333 | ) | ||||||||
Total before income taxes | (150 | ) | (146 | ) | (300 | ) | (293 | ) | ||||||||
Income tax benefit | 61 | 58 | 120 | 117 | ||||||||||||
Net of tax | $ | (89 | ) | $ | (88 | ) | $ | (180 | ) | $ | (176 | ) | ||||
Gains and losses on commodity contracts cash flow hedges | ||||||||||||||||
Propane swap agreements (2) | $ | 77 | $ | — | $ | 465 | $ | (322 | ) | |||||||
Natural gas futures (2) | 631 | 211 | 1,781 | 359 | ||||||||||||
Total before income taxes | 708 | 211 | 2,246 | 37 | ||||||||||||
Income tax (expense) benefit | (273 | ) | (81 | ) | (872 | ) | (8 | ) | ||||||||
Net of tax | 435 | 130 | 1,374 | 29 | ||||||||||||
Total reclassifications for the period | $ | 346 | $ | 42 | $ | 1,194 | $ | (147 | ) | |||||||
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 8, Employee Benefit Plans, for additional details.
(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 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 expense in the accompanying condensed consolidated statements of income.
8. | Employee Benefit Plans |
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2017 and 2016 are set forth in the following tables:
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Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | ||||||||||||||||||||||||||||||||||||
For the Three Months Ended June 30, | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||
Interest cost | $ | 103 | $ | 105 | $ | 624 | $ | 630 | $ | 22 | $ | 23 | $ | 11 | $ | 11 | $ | 13 | $ | 14 | ||||||||||||||||||||
Expected return on plan assets | (127 | ) | (131 | ) | (700 | ) | (701 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
Amortization of prior service credit | — | — | — | — | — | — | (20 | ) | (20 | ) | — | — | ||||||||||||||||||||||||||||
Amortization of net loss | 106 | 103 | 131 | 128 | 22 | 22 | 17 | 17 | — | — | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) | 82 | 77 | 55 | 57 | 44 | 45 | 8 | 8 | 13 | 14 | ||||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset | — | — | 191 | 191 | — | — | — | — | 2 | 2 | ||||||||||||||||||||||||||||||
Total periodic cost | $ | 82 | $ | 77 | $ | 246 | $ | 248 | $ | 44 | $ | 45 | $ | 8 | $ | 8 | $ | 15 | $ | 16 | ||||||||||||||||||||
Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | ||||||||||||||||||||||||||||||||||||
For the Six Months Ended June 30, | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||
Interest cost | 206 | $ | 210 | 1,247 | $ | 1,259 | $ | 44 | $ | 46 | $ | 21 | $ | 21 | $ | 26 | $ | 28 | ||||||||||||||||||||||
Expected return on plan assets | (254 | ) | (261 | ) | (1,399 | ) | (1,402 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
Amortization of prior service credit | — | — | — | — | — | — | (39 | ) | (40 | ) | — | — | ||||||||||||||||||||||||||||
Amortization of net loss | 213 | 206 | 262 | 257 | 44 | 44 | 32 | 34 | — | — | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) | 165 | 155 | 110 | 114 | 88 | 90 | 14 | 15 | 26 | 28 | ||||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset | — | — | 381 | 381 | — | — | — | — | 4 | 4 | ||||||||||||||||||||||||||||||
Total periodic cost | $ | 165 | $ | 155 | $ | 491 | $ | 495 | $ | 88 | $ | 90 | $ | 14 | $ | 15 | $ | 30 | $ | 32 | ||||||||||||||||||||
We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2017. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $1.7 million and approximately $2.1 million at June 30, 2017 and December 31, 2016, respectively.
Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.
The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended June 30, 2017 and 2016:
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For the Three Months Ended June 30, 2017 | Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Prior service credit | $ | — | $ | — | $ | — | $ | (20 | ) | $ | — | $ | (20 | ) | ||||||||||
Net loss | 106 | 131 | 22 | 17 | — | 276 | ||||||||||||||||||
Total recognized in net periodic benefit cost | 106 | 131 | 22 | (3 | ) | — | 256 | |||||||||||||||||
Recognized from accumulated other comprehensive loss (1) | 106 | 25 | 22 | (3 | ) | — | 150 | |||||||||||||||||
Recognized from regulatory asset | — | 106 | — | — | — | 106 | ||||||||||||||||||
Total | $ | 106 | $ | 131 | $ | 22 | $ | (3 | ) | $ | — | $ | 256 | |||||||||||
For the Three Months Ended June 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 | 128 | 22 | 17 | — | 270 | ||||||||||||||||||
Total recognized in net periodic benefit cost | 103 | 128 | 22 | (3 | ) | — | 250 | |||||||||||||||||
Recognized from accumulated other comprehensive loss (1) | 103 | 24 | 22 | (3 | ) | — | 146 | |||||||||||||||||
Recognized from regulatory asset | — | 104 | — | — | — | 104 | ||||||||||||||||||
Total | $ | 103 | $ | 128 | $ | 22 | $ | (3 | ) | $ | ||||||||||||||