Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP | cpk3312017ex-322.htm |
| EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP | cpk3312017ex-321.htm |
| EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP | cpk3312017ex-312.htm |
| EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP | cpk3312017ex-311.htm |
| EX-10.1 - EXHIBIT 10.1 - CHESAPEAKE UTILITIES CORP | cpk3312017ex-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: March 31, 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 — 16,335,052 shares outstanding as of April 30, 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
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 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 on October 8, 2015
MDE: Maryland Department of Environment
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
MWH: Megawatt hour, which is a unit of measurement for electricity
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 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 environmental site
SCO: Standard Choice Offer, a program offered by Columbia Gas in which PESCO was selected as a natural gas supplier pursuant to a competitive auction to serve a pool of customers within Columbia Gas' service territory from April 2016 through March 2017
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
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 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
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 | |||||||||
March 31, | |||||||||
2017 | 2016 | ||||||||
(in thousands, except shares and per share data) | |||||||||
Operating Revenues | |||||||||
Regulated Energy | $ | 97,654 | $ | 89,216 | |||||
Unregulated Energy and other | 87,506 | 57,080 | |||||||
Total Operating Revenues | 185,160 | 146,296 | |||||||
Operating Expenses | |||||||||
Regulated Energy cost of sales | 40,244 | 34,905 | |||||||
Unregulated Energy and other cost of sales | 60,754 | 34,024 | |||||||
Operations | 32,913 | 27,159 | |||||||
Maintenance | 3,231 | 2,479 | |||||||
Depreciation and amortization | 8,812 | 7,503 | |||||||
Other taxes | 4,530 | 3,846 | |||||||
Total Operating Expenses | 150,484 | 109,916 | |||||||
Operating Income | 34,676 | 36,380 | |||||||
Other expense, net | (277 | ) | (34 | ) | |||||
Interest charges | 2,739 | 2,650 | |||||||
Income Before Income Taxes | 31,660 | 33,696 | |||||||
Income taxes | 12,516 | 13,329 | |||||||
Net Income | $ | 19,144 | $ | 20,367 | |||||
Weighted Average Common Shares Outstanding: | |||||||||
Basic | 16,317,224 | 15,286,842 | |||||||
Diluted | 16,363,796 | 15,331,912 | |||||||
Earnings Per Share of Common Stock: | |||||||||
Basic | $ | 1.17 | $ | 1.33 | |||||
Diluted | $ | 1.17 | $ | 1.33 | |||||
Cash Dividends Declared Per Share of Common Stock | $ | 0.3050 | $ | 0.2875 | |||||
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Net Income | $ | 19,144 | $ | 20,367 | ||||
Other Comprehensive Income (Loss), net of tax: | ||||||||
Employee Benefits, net of tax: | ||||||||
Amortization of prior service cost, net of tax of $(8) and $(8), respectively | (11 | ) | (12 | ) | ||||
Net gain, net of tax of $77 and $67, respectively | 93 | 101 | ||||||
Cash Flow Hedges, net of tax: | ||||||||
Unrealized gain on commodity contract cash flow hedges, net of tax of $192 and $0, respectively | 338 | — | ||||||
Total Other Comprehensive Income | 420 | 89 | ||||||
Comprehensive Income | $ | 19,564 | $ | 20,456 | ||||
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Assets | March 31, 2017 | December 31, 2016 | ||||||
(in thousands, except shares and per share data) | ||||||||
Property, Plant and Equipment | ||||||||
Regulated Energy | $ | 985,832 | $ | 957,681 | ||||
Unregulated Energy | 199,211 | 196,800 | ||||||
Other businesses and eliminations | 21,486 | 21,114 | ||||||
Total property, plant and equipment | 1,206,529 | 1,175,595 | ||||||
Less: Accumulated depreciation and amortization | (250,574 | ) | (245,207 | ) | ||||
Plus: Construction work in progress | 62,362 | 56,276 | ||||||
Net property, plant and equipment | 1,018,317 | 986,664 | ||||||
Current Assets | ||||||||
Cash and cash equivalents | 5,700 | 4,178 | ||||||
Accounts receivable (less allowance for uncollectible accounts of $815 and $909, respectively) | 58,375 | 62,803 | ||||||
Accrued revenue | 16,317 | 16,986 | ||||||
Propane inventory, at average cost | 5,437 | 6,457 | ||||||
Other inventory, at average cost | 3,657 | 4,576 | ||||||
Regulatory assets | 7,527 | 7,694 | ||||||
Storage gas prepayments | 735 | 5,484 | ||||||
Income taxes receivable | 13,388 | 22,888 | ||||||
Prepaid expenses | 4,534 | 6,792 | ||||||
Mark-to-market energy assets | 1,339 | 823 | ||||||
Other current assets | 1,804 | 2,470 | ||||||
Total current assets | 118,813 | 141,151 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 15,070 | 15,070 | ||||||
Other intangible assets, net | 1,752 | 1,843 | ||||||
Investments, at fair value | 5,212 | 4,902 | ||||||
Regulatory assets | 76,218 | 76,803 | ||||||
Receivables and other deferred charges | 2,929 | 2,786 | ||||||
Total deferred charges and other assets | 101,181 | 101,404 | ||||||
Total Assets | $ | 1,238,311 | $ | 1,229,219 | ||||
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
Capitalization and Liabilities | March 31, 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) | 7,949 | 7,935 | ||||||
Additional paid-in capital | 251,144 | 250,967 | ||||||
Retained earnings | 206,194 | 192,062 | ||||||
Accumulated other comprehensive loss | (4,458 | ) | (4,878 | ) | ||||
Deferred compensation obligation | 3,100 | 2,416 | ||||||
Treasury stock | (3,100 | ) | (2,416 | ) | ||||
Total stockholders’ equity | 460,829 | 446,086 | ||||||
Long-term debt, net of current maturities | 136,537 | 136,954 | ||||||
Total capitalization | 597,366 | 583,040 | ||||||
Current Liabilities | ||||||||
Current portion of long-term debt | 12,111 | 12,099 | ||||||
Short-term borrowing | 199,333 | 209,871 | ||||||
Accounts payable | 49,500 | 56,935 | ||||||
Customer deposits and refunds | 29,638 | 29,238 | ||||||
Accrued interest | 2,868 | 1,312 | ||||||
Dividends payable | 4,981 | 4,973 | ||||||
Accrued compensation | 5,560 | 10,496 | ||||||
Regulatory liabilities | 7,275 | 1,291 | ||||||
Mark-to-market energy liabilities | 189 | 773 | ||||||
Other accrued liabilities | 9,278 | 7,063 | ||||||
Total current liabilities | 320,733 | 334,051 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes | 231,004 | 222,894 | ||||||
Regulatory liabilities | 42,861 | 43,064 | ||||||
Environmental liabilities | 8,535 | 8,592 | ||||||
Other pension and benefit costs | 33,082 | 32,828 | ||||||
Deferred investment tax credits and other liabilities | 4,730 | 4,750 | ||||||
Total deferred credits and other liabilities | 320,212 | 312,128 | ||||||
Environmental and other commitments and contingencies (Note 4 and 5) | ||||||||
Total Capitalization and Liabilities | $ | 1,238,311 | $ | 1,229,219 | ||||
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Operating Activities | ||||||||
Net income | $ | 19,144 | $ | 20,367 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 8,812 | 7,503 | ||||||
Depreciation and accretion included in other costs | 1,939 | 1,646 | ||||||
Deferred income taxes | 7,849 | 4,326 | ||||||
Realized loss on commodity contracts/sale of assets/investments | 1,330 | 479 | ||||||
Unrealized loss on investments/commodity contracts | 132 | 18 | ||||||
Employee benefits and compensation | 423 | 380 | ||||||
Share-based compensation | 639 | 649 | ||||||
Other, net | (4 | ) | 24 | |||||
Changes in assets and liabilities: | ||||||||
Accounts receivable and accrued revenue | 5,095 | (3,738 | ) | |||||
Propane inventory, storage gas and other inventory | 6,688 | 3,073 | ||||||
Regulatory assets/liabilities, net | 6,103 | 3,941 | ||||||
Prepaid expenses and other current assets | 1,136 | 1,358 | ||||||
Accounts payable and other accrued liabilities | (5,897 | ) | 102 | |||||
Income taxes receivable | 9,500 | 8,841 | ||||||
Customer deposits and refunds | 400 | (134 | ) | |||||
Accrued compensation | (4,966 | ) | (5,943 | ) | ||||
Other assets and liabilities, net | 1,631 | 1,242 | ||||||
Net cash provided by operating activities | 59,954 | 44,134 | ||||||
Investing Activities | ||||||||
Property, plant and equipment expenditures | (42,172 | ) | (37,783 | ) | ||||
Proceeds from sales of assets | 36 | 51 | ||||||
Environmental expenditures | (57 | ) | (99 | ) | ||||
Net cash used in investing activities | (42,193 | ) | (37,831 | ) | ||||
Financing Activities | ||||||||
Common stock dividends | (4,815 | ) | (4,204 | ) | ||||
Issuance of stock for Dividend Reinvestment Plan | 222 | 195 | ||||||
Tax withholding payments related to net settled stock compensation | (692 | ) | (770 | ) | ||||
Change in cash overdrafts due to outstanding checks | 587 | (1,501 | ) | |||||
Net (repayment) borrowing under line of credit agreements | (11,125 | ) | 839 | |||||
Repayment of long-term debt and capital lease obligation | (416 | ) | (402 | ) | ||||
Net cash used by financing activities | (16,239 | ) | (5,843 | ) | ||||
Net Increase in Cash and Cash Equivalents | 1,522 | 460 | ||||||
Cash and Cash Equivalents—Beginning of Period | 4,178 | 2,855 | ||||||
Cash and Cash Equivalents—End of Period | $ | 5,700 | $ | 3,315 | ||||
The accompanying notes are an integral part of these financial statements.
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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 | — | — | — | 19,144 | — | — | — | 19,144 | ||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 420 | — | — | 420 | ||||||||||||||||||||||
Dividend declared ($0.3050 per share) | — | — | — | (5,012 | ) | — | — | — | (5,012 | ) | ||||||||||||||||||||
Dividend reinvestment plan | 5,733 | 3 | 376 | — | — | — | — | 379 | ||||||||||||||||||||||
Share-based compensation and tax benefit (4) (5) | 22,657 | 11 | (199 | ) | — | — | — | — | (188 | ) | ||||||||||||||||||||
Treasury stock activities | — | — | — | — | — | 684 | (684 | ) | — | |||||||||||||||||||||
Balance at March 31, 2017 | 16,331,889 | $ | 7,949 | $ | 251,144 | $ | 206,194 | $ | (4,458 | ) | $ | 3,100 | $ | (3,100 | ) | $ | 460,829 | |||||||||||||
(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 86,899 and 76,745 shares at March 31, 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 three months ended March 31, 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.
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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 have revised the unaudited condensed consolidated statement of cash flows for the three months ended March 31, 2016 to reflect only property, plant and equipment expenditures paid in cash within the Investing Activities section. The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section. These revisions are considered immaterial to the overall presentation of our unaudited condensed consolidated financial statements.
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. 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.
In preparation for the adoption of this standard, we have analyzed our existing businesses and revenue streams and have prepared a preliminary gap analysis between our current revenue policies and the requirements under the new revenue recognition standard. We are in the process of evaluating each revenue stream under the new standard, expanding the contract sampling, creating new policies and evaluating the enhanced disclosure requirements. We will provide additional training to our employees and develop processes and system changes associated with the implementation of the new standard, and we will then implement the standard. We plan to utilize the modified retrospective transition method upon adoption of this standard.
Based on our assessment, we do not believe the new standard will impact the recognition of revenue from a majority of our customers. However, we have just begun to evaluate our long-term special contracts, and may find facts and circumstances in those contracts that could impact the timing of the recognition of revenue. As we continue to execute our plan related to this standard, we will be in a better position to quantify the full impact of this standard.
Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using the modified retrospective
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transition method 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 this update may have on our financial position and results of operations.
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 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 financial position and results of operations.
2. | Calculation of Earnings Per Share |
Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands, except shares and per share data) | ||||||||
Calculation of Basic Earnings Per Share: | ||||||||
Net Income | $ | 19,144 | $ | 20,367 | ||||
Weighted average shares outstanding | 16,317,224 | 15,286,842 | ||||||
Basic Earnings Per Share | $ | 1.17 | $ | 1.33 | ||||
Calculation of Diluted Earnings Per Share: | ||||||||
Reconciliation of Numerator: | ||||||||
Net Income | $ | 19,144 | $ | 20,367 | ||||
Reconciliation of Denominator: | ||||||||
Weighted shares outstanding—Basic | 16,317,224 | 15,286,842 | ||||||
Effect of dilutive securities—Share-based compensation | 46,572 | 45,070 | ||||||
Adjusted denominator—Diluted | 16,363,796 | 15,331,912 | ||||||
Diluted Earnings Per Share | $ | 1.17 | $ | 1.33 | ||||
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.
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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. In March 2017, after consideration of the legal briefs filed and oral arguments held in the proceeding, the Supreme Court reversed the Florida PSC decision. As a result, FPU will exclude the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause filing.
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. We requested approval to invest approximately $59.8 million over a five-year period associated with this 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. FPU will prepare and file a limited proceeding, as recommended by the Florida PSC, before the end of 2017.
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. Eastern Shore proposed to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and add additional 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. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment in the certificate proceeding. However, FERC’s determination does not prevent Eastern Shore from proposing rolled-in rate treatment of these project facilities in a future general rate case. In August 2016, the FERC issued a “Notice to Proceed,” and Eastern Shore commenced construction.
Upon receiving the FERC's approval in December 2016, the Daleville and Kemblesville Loops commenced operation. Upon receiving the FERC's approval, the Delaware City Compressor Station commenced service in March 2017. As of the end of March 2017, the entire project was placed into service. The total cost to complete the project is 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. 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. In July 2016, the FERC ordered that Eastern Shore’s request for a determination of rolled-in rate treatment may be addressed in its next base rate proceeding and required Eastern Shore to comply with 19 environmental conditions.
In September 2016, the FERC granted approval to start construction on all phases 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. In December 2016, Eastern Shore filed a request to place into service the pipeline looping located in New Castle County, Delaware. The FERC granted approval to place the Porter Road Loop into service in December 2016. The
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remaining components of the project, the Bridgeville Compressor Station and the Dover Loop, are anticipated to be completed by the end of May 2017. Eastern Shore continues to file weekly status reports with the FERC in compliance with the environmental conditions. The estimated cost of the project is approximately $37.0 million. We expect that 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 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 four existing customers as well as Chesapeake affiliates, 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 to the docket. In February 2017, Eastern Shore submitted responses to the FERC staff's data requests. The FERC has scheduled issuance of the environmental assessment for this project in May 2017, with approval of the project anticipated in August 2017. The estimated cost of this expansion project is $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 are 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 Mainline Expansion and Lateral projects, each of 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. Accordingly, the new rates are to become effective, subject to refund, on August 1, 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 March 31, 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 $10.7 million has been recovered as of March 31, 2017, leaving approximately $3.3 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.
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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. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.
We expect that similar remedial actions will ultimately be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 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-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 March 31, 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 March 31, 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. 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, in October 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 in January 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. Groundwater monitoring results from testing conducted in October 2016 indicated that natural attenuation default criteria were met at all wells.
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
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corrective measures for lake sediments are not warranted and will not be required by FDEP. We therefore, have not recorded a liability for sediment remediation.
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 are anticipated to be available 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.
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.
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 Delaware and Maryland divisions 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 had 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 3.1 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 3.1 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 March 31, 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
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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
The Board of Directors has authorized us to issue corporate guarantees and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is $85.0 million.
We have issued corporate guarantees to certain of our subsidiaries' vendors, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2017 was approximately $56.6 million, with the guarantees expiring on various dates through April 2018.
We have notified all of Xeron's counterparties holding parental guarantees that Xeron began winding down operations during the first quarter of 2017. Upon the winding down of Xeron's business, the corporate guarantees were canceled in accordance with their respective terms and conditions.
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).
We issued letters of credit totaling approximately $7.0 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 December 2017. There have been no draws on these letters of credit as of March 31, 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 comprise two reportable segments:
• | Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore. |
• | Unregulated Energy. The Unregulated Energy segment includes propane distribution 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. As of March 31, 2017, this segment also included the operations of Xeron, our former propane and crude oil trading subsidiary that began winding down operations during the quarter. 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.
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The following table presents financial information about our reportable segments:
Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Regulated Energy segment | $ | 96,446 | $ | 88,894 | ||||
Unregulated Energy segment | 88,714 | 57,402 | ||||||
Total operating revenues, unaffiliated customers | $ | 185,160 | $ | 146,296 | ||||
Intersegment Revenues (1) | ||||||||
Regulated Energy segment | $ | 1,208 | $ | 322 | ||||
Unregulated Energy segment | 4,011 | 113 | ||||||
Other businesses | 228 | 226 | ||||||
Total intersegment revenues | $ | 5,447 | $ | 661 | ||||
Operating Income | ||||||||
Regulated Energy segment | $ | 23,017 | $ | 24,319 | ||||
Unregulated Energy segment | 11,530 | 11,936 | ||||||
Other businesses and eliminations | 129 | 125 | ||||||
Total operating income | 34,676 | 36,380 | ||||||
Other expense, net | (277 | ) | (34 | ) | ||||
Interest | 2,739 | 2,650 | ||||||
Income before Income Taxes | 31,660 | 33,696 | ||||||
Income taxes | 12,516 | 13,329 | ||||||
Net Income | $ | 19,144 | $ | 20,367 | ||||
(1) | All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. |
(in thousands) | March 31, 2017 | December 31, 2016 | ||||||
Identifiable Assets | ||||||||
Regulated Energy segment | $ | 1,000,265 | $ | 986,752 | ||||
Unregulated Energy segment | 213,078 | 226,368 | ||||||
Other businesses and eliminations | 24,968 | 16,099 | ||||||
Total identifiable assets | $ | 1,238,311 | $ | 1,229,219 | ||||
Our operations are entirely domestic.
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7. | Stockholder's Equity |
Preferred Stock
We had 2,000,000 authorized and unissued shares of $0.01 par value preferred stock as of March 31, 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
Our Certificate of Incorporation contains a Rights Plan, pursuant to which 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. 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 three months ended March 31, 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 | ) | 1,278 | 1,269 | ||||||||
Amounts reclassified from accumulated other comprehensive loss | 91 | (940 | ) | (849 | ) | |||||||
Net current-period other comprehensive income | 82 | 338 | 420 | |||||||||
As of March 31, 2017 | $ | (5,278 | ) | $ | 820 | $ | (4,458 | ) | ||||
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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 loss before reclassifications | — | (283 | ) | (283 | ) | |||||||
Amounts reclassified from accumulated other comprehensive loss | 89 | 283 | 372 | |||||||||
Net prior-period other comprehensive income | 89 | — | 89 | |||||||||
As of March 31, 2016 | $ | (5,491 | ) | $ | (260 | ) | $ | (5,751 | ) | |||
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2017 and 2016. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Amortization of defined benefit pension and postretirement plan items: | ||||||||
Prior service credit (1) | $ | 19 | $ | 20 | ||||
Net loss(1) | (170 | ) | (168 | ) | ||||
Total before income taxes | (151 | ) | (148 | ) | ||||
Income tax benefit | 60 | 59 | ||||||
Net of tax | $ | (91 | ) | $ | (89 | ) | ||
Gains and losses on commodity contracts cash flow hedges | ||||||||
Propane swap agreements (2) | $ | 388 | $ | (322 | ) | |||
Natural gas futures (2) | 1,150 | (149 | ) | |||||
Total before income taxes | 1,538 | (471 | ) | |||||
Income tax (expense) benefit | (598 | ) | 188 | |||||
Net of tax | 940 | (283 | ) | |||||
Total reclassifications for the period | $ | 849 | $ | (372 | ) | |||
(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 months ended March 31, 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 March 31, | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | 2017 | 2016 | ||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||
Interest cost | $ | 103 | $ | 105 | $ | 623 | $ | 630 | $ | 22 | $ | 23 | $ | 10 | $ | 11 | $ | 13 | $ | 14 | ||||||||||||||||||||
Expected return on plan assets | (127 | ) | (131 | ) | (699 | ) | (701 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
Amortization of prior service credit | — | — | — | — | — | — | (19 | ) | (20 | ) | — | — | ||||||||||||||||||||||||||||
Amortization of net loss | 107 | 104 | 131 | 128 | 22 | 22 | 16 | 18 | — | — | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) | 83 | 78 | 55 | 57 | 44 | 45 | 7 | 9 | 13 | 14 | ||||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset | — | — | 191 | 191 | — | — | — | — | 2 | 2 | ||||||||||||||||||||||||||||||
Total periodic cost | $ | 83 | $ | 78 | $ | 246 | $ | 248 | $ | 44 | $ | 45 | $ | 7 | $ | 9 | $ | 15 | $ | 16 | ||||||||||||||||||||
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 $1.9 million and approximately $2.1 million at March 31, 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 March 31, 2017 and 2016:
For the Three Months Ended March 31, 2017 | Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Prior service credit | $ | — | $ | — | $ | — | $ | (19 | ) | $ | — | $ | (19 | ) | ||||||||||
Net loss | 107 | 131 | 22 | 16 | — | 276 | ||||||||||||||||||
Total recognized in net periodic benefit cost | 107 | 131 | 22 | (3 | ) | — | 257 | |||||||||||||||||
Recognized from accumulated other comprehensive loss (1) | 107 | 25 | 22 | (3 | ) | — | 151 | |||||||||||||||||
Recognized from regulatory asset | — | 106 | — | — | — | 106 | ||||||||||||||||||
Total | $ | 107 | $ | 131 | $ | 22 | $ | (3 | ) | $ | — | $ | 257 | |||||||||||
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For the Three Months Ended March 31, 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 | 104 | 128 | 22 | 18 | — | 272 | ||||||||||||||||||
Total recognized in net periodic benefit cost | 104 | 128 | 22 | (2 | ) | — | 252 | |||||||||||||||||
Recognized from accumulated other comprehensive loss (1) | 104 | 24 | 22 | (2 | ) | — | 148 | |||||||||||||||||
Recognized from regulatory asset | — | 104 | — | — | — | 104 | ||||||||||||||||||
Total | $ | 104 | $ | 128 | $ | 22 | $ | (2 | ) | $ | — | $ | 252 | |||||||||||
(1) See Note 7, Stockholder's Equity.
During the three months ended March 31, 2017, we contributed approximately $48,000 to the Chesapeake Pension Plan and approximately $374,000 to the FPU Pension Plan. We expect to contribute a total of approximately $746,000 and approximately $3.0 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2017, which represents 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 months ended March 31, 2017, were approximately $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2017. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2017, were approximately $49,000. We estimate that approximately $83,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2017. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2017, were approximately $26,000. We estimate that approximately $129,000 will be paid for such benefits under the FPU Medical Plan in 2017.
9. | Investments |
The investment balances at March 31, 2017 and December 31, 2016, consisted of the following:
(in thousands) | March 31, 2017 | December 31, 2016 | |||||
Rabbi trust (associated with the Deferred Compensation Plan) | $ | 5,190 | $ | 4,881 | |||
Investments in equity securities | 22 | 21 | |||||
Total | $ | 5,212 | 4,902 | ||||
We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2017 and 2016, we recorded a net unrealized gain of approximately $252,000 and a net unrealized loss of $18,000, 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.
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 months ended March 31, 2017 and 2016:
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Three Months Ended | ||||||||
March 31, | ||||||||
2017 | 2016 | |||||||
(in thousands) | ||||||||
Awards to non-employee directors | $ | 135 | $ | 165 | ||||
Awards to key employees | 504 | 484 | ||||||
Total compensation expense | 639 | 649 | ||||||
Less: tax benefit | (257 | ) | (261 | ) | ||||
Share-based compensation amounts included in net income | $ | 382 | $ | 388 | ||||
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, each of our non-employee directors received an annual retainer of 953 shares of common stock under the SICP for service as a director through the 2017 Annual Meeting of Stockholders. At March 31, 2017, there was approximately $45,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service period ending April 30, 2017.
Key Employees
The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2017:
Number of Shares | Weighted Average Fair Value | ||||||
Outstanding— December 31, 2016 | 115,091 | $ | 51.85 | ||||
Granted | 38,517 | $ | 62.08 | ||||
Vested | (32,926 | ) | $ | 38.88 | |||
Expired | (1,878 | ) | $ | 39.97 | |||
Outstanding— March 31, 2017 | 118,804 | $ | 56.03 | ||||
In January 2017, our Board of Directors granted awards of 38,517 shares of common stock to key employees under the SICP. The shares granted in January 2017 are multi-year awards that will vest at the end of the three-year service period ending December 31, 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, 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 March 31, 2017, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $8.2 million. At March 31, 2017, there was approximately $3.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2017 through 2020.
Stock Options
We did not have any stock options outstanding at March 31, 2017 or 2016, nor were any stock options issued during these periods.
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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. Our 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 March 31, 2017, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Hedging Activities in 2017
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 have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2017, PESCO had a total of 2.7 million Dts hedged under natural gas futures contracts, with an asset fair value of approximately $1.2 million. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).
The impact of financial instruments that have not been designated as hedges on our condensed consolidated financial statements for the quarter ended March 31, 2017 was $189,000, which was recorded as an increase in gas costs and is associated with 813,000 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 4.8 million gallons expected to be purchased through September 2017, of which 1.4 million gallons were outstanding at March 31, 2017. Under the swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2016 through September 2017) and the swap prices of $0.5225 and $0.5650 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 March 31, 2017, the remaining swap agreements had a fair value of approximately $137,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).
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 was no ineffective portion of this hedge.
In January 2016, PESCO entered into a SCO supplier agreement with Columbia Gas to provide natural gas supply for one of its local distribution customer pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, which terminated 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. 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 discontinued hedge accounting as the hedges were no longer highly effective. As of March 31, 2017, these contracts have all expired and are no longer reported on the balance sheet.
Commodity Contracts for Trading Activities
During the first quarter of 2017, Xeron began winding down operations. Prior to March 31, 2017, Xeron engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts were considered derivatives and were 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 were recognized as unrealized gains or losses in the statements of income for the period of change. As of March 31, 2017, Xeron had no outstanding contracts that were accounted for as derivatives.
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The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2017 and December 31, 2016, are as follows:
Asset Derivatives | ||||||||||
Fair Value As Of | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2017 | December 31, 2016 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Propane swap agreements | Mark-to-market energy assets | $ | 4 | $ | 8 | |||||
Put options | Mark-to-market energy assets | — | 9 | |||||||
Derivatives designated as cash flow hedges | ||||||||||
Natural gas futures contracts | Mark-to-market energy assets | 1,198 | 113 | |||||||
Propane swap agreements | Mark-to-market energy assets | 137 | 693 | |||||||
Total asset derivatives | $ | 1,339 | $ | 823 | ||||||
Liability Derivatives | ||||||||||
Fair Value As Of | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2017 | December 31, 2016 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Natural gas futures contracts | Mark-to-market energy liabilities | $ | 189 | $ | 773 | |||||
Total liability derivatives | $ | 189 | $ | 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: | |||||||||||
Location of Gain | For the Three Months Ended March 31, | ||||||||||
(in thousands) | (Loss) on Derivatives | 2017 | 2016 | ||||||||
Derivatives not designated as hedging instruments | |||||||||||
Realized (loss) gain on forward contracts and options (1) | Revenue | $ | 112 | $ | 187 | ||||||
Unrealized gain on forward contracts (1) | Revenue | — | 1 | ||||||||
Natural gas futures contracts | Cost of sales | 124 | — | ||||||||
Propane swap agreements | Cost of sales | (4 | ) | — | |||||||
Derivatives designated as fair value hedges | |||||||||||
Put /Call option (2) | Cost of sales | (9 | ) | 73 | |||||||
Derivatives designated as cash flow hedges | |||||||||||
Propane swap agreements | Cost of sales | 388 | (364 | ) | |||||||
Propane swap agreements | Other Comprehensive Loss | (557 | ) | — | |||||||
Natural gas futures contracts | Cost of sales | 1,150 | 149 | ||||||||
Natural gas futures contracts | Other Comprehensive Income (Loss) | 1,087 | (462 | ) | |||||||
Total | $ | 2,291 | $ | (416 | ) | ||||||
(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. |
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(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. |
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 March 31, 2017 and December 31, 2016:
Fair Value Measurements Using: | ||||||||||||||||
As of March 31, 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 | $ | 22 | $ | 22 | $ | — | $ | — | ||||||||
Investments—guaranteed income fund | 565 | — | — | 565 | ||||||||||||
Investments—mutual funds and other | 4,625 | 4,625 | — | — | ||||||||||||
Total investments | 5,212 | 4,647 | — | 565 | ||||||||||||
Mark-to-market energy assets, incl. natural gas futures contracts and swap agreements | 1,339 | — | 1,339 | — | ||||||||||||
Total assets | $ | 6,551 | $ | 4,647 | $ | 1,339 | $ | 565 | ||||||||
Liabilities: | ||||||||||||||||
Mark-to-market energy liabilities including natural gas futures contracts | $ | 189 | $ | — | $ | 189 | $ | — | ||||||||
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Fair Value Measurements Using: | ||||||||||||||||
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 | $ | 21 | $ | 21 | $ | — | $ | — | ||||||||
Investments—guaranteed income fund | 561 | — | — | 561 | ||||||||||||
Investments—mutual funds and other | 4,320 | 4,320 | — | — | ||||||||||||
Total investments | 4,902 | 4,341 | — | 561 | ||||||||||||
Mark-to-market energy assets, incl. natural gas futures contracts and swap agreements | 823 | — | 823 | — | ||||||||||||
Total assets | $ | 5,725 | $ | 4,341 | $ | 823 | $ | 561 | ||||||||
Liabilities: | ||||||||||||||||
Mark-to-market energy liabilities including natural gas futures contracts | $ | 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 March 31, 2017 and December 31, 2016:
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: