Attached files
| file | filename |
|---|---|
| EX-32.2 - EXHIBIT 32.2 - CHESAPEAKE UTILITIES CORP | cpk3312016ex-322.htm |
| EX-32.1 - EXHIBIT 32.1 - CHESAPEAKE UTILITIES CORP | cpk3312016ex-321.htm |
| EX-31.2 - EXHIBIT 31.2 - CHESAPEAKE UTILITIES CORP | cpk3312016ex-312.htm |
| EX-31.1 - EXHIBIT 31.1 - CHESAPEAKE UTILITIES CORP | cpk3312016ex-311.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, 2016
OR
¨ | TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 |
For the transition period from to
Commission File Number: 001-11590
CHESAPEAKE UTILITIES CORPORATION (Exact name of registrant as specified in its charter) | ||
Delaware | 51-0064146 | |
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.) | |
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrant’s telephone number, including area code)
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer | x | Accelerated filer | ¨ | |||
Non-accelerated filer | ¨ | Smaller reporting company | ¨ | |||
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x
Common Stock, par value $0.4867 — 15,308,467 shares outstanding as of April 30, 2016.
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 into which Gatherco merged on April 1, 2015
CDD: Cooling degree-day, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit
Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake Utilities
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake Utilities
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake Utilities
CHP: A combined heat and power plant being constructed by Eight Flags in Nassau County, Florida
Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure
Credit Agreement: An agreement between 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 and fees
Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia
DNREC: Delaware Department of Natural Resources and Environmental Control
Dts/d: Dekatherms per day
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake Utilities
EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of ESG
Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC
EPA: United States Environmental Protection Agency
ESG: Eastern Shore Gas Company and its affiliates
FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission, an independent agency of the United States government that regulates the interstate transmission of electricity, natural gas, and oil
FDEP: Florida Department of Environmental Protection
FDOT: Florida Department of Transportation
FGT: Florida Gas Transmission Company
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities
FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake Utilities
FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake Utilities
GAAP: Accounting principles generally accepted in the United States of America
Gatherco: Gatherco, Inc.
GRIP: The Gas Reliability Infrastructure Program is a natural gas pipeline replacement program in Florida, pursuant to which we collect a surcharge from certain of our Florida customers to recover capital and other program-related costs associated with the replacement of qualifying distribution mains and services in Florida
Gulf Power: Gulf Power Company
Gulfstream: Gulfstream Natural Gas System, LLC
HDD: Heating degree-day, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit
JEA: The community-owned utility located in Jacksonville, Florida, formerly known as Jacksonville Electric Authority
Lenders: PNC, Bank of America N.A., Citizens Bank N.A., Royal Bank of Canada, and Wells Fargo Bank, National Association, which are collectively the lenders that entered into the Credit Agreement 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
NAM: Natural Attenuation Monitoring
Note Agreement: Note Purchase Agreement entered into by Chesapeake Utilities with the Note Holders on September 5, 2013
Note Holders: PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company, which are collectively the lenders that entered into the Note Agreement with Chesapeake Utilities on September 5, 2013
Notes: Series A and B Unsecured Senior Notes that were entered into with the Note Holders
NYSE: New York Stock Exchange
OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, a new tariff associated with Eastern Shore's firm transportation service that will allow Eastern Shore not to schedule service for up to 90 days during the peak months of November through April
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., our wholly-owned Florida intrastate pipeline subsidiary
PESCO: Peninsula Energy Services Company, Inc., our 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 for the future purchase of our Shelf Notes
PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake Utilities’ natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida
RAP: Remedial Action Plan, which is a plan that outlines the procedures taken or being considered in removing contaminants from a MGP formerly owned by Chesapeake Utilities or FPU
Revolver: The unsecured revolving credit facility issued to us by the Lenders
Sandpiper: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities providing a tariff-based distribution service to customers in Worcester County, Maryland
Sanford Group: FPU and other responsible parties involved with the Sanford environmental site
SEC: Securities and Exchange Commission
Sharp: Sharp Energy, Inc., our 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, over the next three years, up to $150.0 million of Shelf Notes at a fixed interest rate and with a maturity date not to exceed twenty 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
Xeron: Xeron, Inc., our propane wholesale marketing subsidiary, based in Houston, Texas
PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
Three Months Ended | |||||||||
March 31, | |||||||||
2016 | 2015 | ||||||||
(in thousands, except shares and per share data) | |||||||||
Operating Revenues | |||||||||
Regulated Energy | $ | 89,216 | $ | 109,582 | |||||
Unregulated Energy | 57,080 | 60,499 | |||||||
Total Operating Revenues | 146,296 | 170,081 | |||||||
Operating Expenses | |||||||||
Regulated Energy cost of sales | 34,905 | 57,129 | |||||||
Unregulated Energy and other cost of sales | 34,024 | 35,234 | |||||||
Operations | 27,159 | 26,945 | |||||||
Maintenance | 2,479 | 2,703 | |||||||
Depreciation and amortization | 7,503 | 6,975 | |||||||
Other taxes | 3,846 | 3,587 | |||||||
Total Operating Expenses | 109,916 | 132,573 | |||||||
Operating Income | 36,380 | 37,508 | |||||||
Other (Expense) Income, net | (34 | ) | 133 | ||||||
Interest charges | 2,650 | 2,448 | |||||||
Income Before Income Taxes | 33,696 | 35,193 | |||||||
Income taxes | 13,329 | 14,084 | |||||||
Net Income | $ | 20,367 | $ | 21,109 | |||||
Weighted Average Common Shares Outstanding: | |||||||||
Basic | 15,286,842 | 14,604,841 | |||||||
Diluted | 15,331,912 | 14,656,310 | |||||||
Earnings Per Share of Common Stock: | |||||||||
Basic | $ | 1.33 | $ | 1.45 | |||||
Diluted | $ | 1.33 | $ | 1.44 | |||||
Cash Dividends Declared Per Share of Common Stock | $ | 0.2875 | $ | 0.2700 | |||||
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, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Net Income | $ | 20,367 | $ | 21,109 | ||||
Other Comprehensive Income (Loss), net of tax: | ||||||||
Employee Benefits, net of tax: | ||||||||
Amortization of prior service cost, net of tax of $(8) and $(7), respectively | (12 | ) | (10 | ) | ||||
Net gain, net of tax of $67 and $62, respectively | 101 | 92 | ||||||
Cash Flow Hedges, net of tax: | ||||||||
Unrealized loss on commodity contract cash flow hedges, net of tax of $- and $17, respectively | — | 26 | ||||||
Total Other Comprehensive Income | 89 | 108 | ||||||
Comprehensive Income | $ | 20,456 | $ | 21,217 | ||||
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, 2016 | December 31, 2015 | ||||||
(in thousands, except shares and per share data) | ||||||||
Property, Plant and Equipment | ||||||||
Regulated Energy | $ | 850,041 | $ | 842,756 | ||||
Unregulated Energy | 147,221 | 145,734 | ||||||
Other businesses and eliminations | 19,430 | 18,999 | ||||||
Total property, plant and equipment | 1,016,692 | 1,007,489 | ||||||
Less: Accumulated depreciation and amortization | (222,650 | ) | (215,313 | ) | ||||
Plus: Construction work in progress | 87,187 | 62,774 | ||||||
Net property, plant and equipment | 881,229 | 854,950 | ||||||
Current Assets | ||||||||
Cash and cash equivalents | 3,315 | 2,855 | ||||||
Accounts receivable (less allowance for uncollectible accounts of $684 and $909, respectively) | 44,434 | 41,007 | ||||||
Accrued revenue | 12,331 | 12,452 | ||||||
Propane inventory, at average cost | 5,412 | 6,619 | ||||||
Other inventory, at average cost | 4,289 | 3,803 | ||||||
Regulatory assets | 6,451 | 8,268 | ||||||
Storage gas prepayments | 1,213 | 3,410 | ||||||
Income taxes receivable | 16,260 | 24,950 | ||||||
Prepaid expenses | 4,982 | 7,146 | ||||||
Mark-to-market energy assets | — | 153 | ||||||
Other current assets | 1,688 | 1,044 | ||||||
Total current assets | 100,375 | 111,707 | ||||||
Deferred Charges and Other Assets | ||||||||
Goodwill | 15,070 | 14,548 | ||||||
Other intangible assets, net | 2,128 | 2,222 | ||||||
Investments, at fair value | 3,674 | 3,644 | ||||||
Regulatory assets | 76,934 | 77,519 | ||||||
Receivables and other deferred charges | 2,574 | 2,831 | ||||||
Total deferred charges and other assets | 100,380 | 100,764 | ||||||
Total Assets | $ | 1,081,984 | $ | 1,067,421 | ||||
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, 2016 | December 31, 2015 | ||||||
(in thousands, except shares and per share data) | ||||||||
Capitalization | ||||||||
Stockholders’ equity | ||||||||
Common stock, par value $0.4867 per share (authorized 25,000,000 shares) | $ | 7,449 | $ | 7,432 | ||||
Additional paid-in capital | 190,389 | 190,311 | ||||||
Retained earnings | 182,165 | 166,235 | ||||||
Accumulated other comprehensive loss | (5,751 | ) | (5,840 | ) | ||||
Deferred compensation obligation | 2,221 | 1,883 | ||||||
Treasury stock | (2,221 | ) | (1,883 | ) | ||||
Total stockholders’ equity | 374,252 | 358,138 | ||||||
Long-term debt, net of current maturities | 148,602 | 149,006 | ||||||
Total capitalization | 522,854 | 507,144 | ||||||
Current Liabilities | ||||||||
Current portion of long-term debt | 9,163 | 9,151 | ||||||
Short-term borrowing | 172,742 | 173,397 | ||||||
Accounts payable | 36,299 | 39,300 | ||||||
Customer deposits and refunds | 27,039 | 27,173 | ||||||
Accrued interest | 3,021 | 1,311 | ||||||
Dividends payable | 4,400 | 4,390 | ||||||
Accrued compensation | 4,107 | 10,014 | ||||||
Regulatory liabilities | 9,313 | 7,365 | ||||||
Mark-to-market energy liabilities | 423 | 433 | ||||||
Other accrued liabilities | 7,942 | 7,059 | ||||||
Total current liabilities | 274,449 | 279,593 | ||||||
Deferred Credits and Other Liabilities | ||||||||
Deferred income taxes | 197,416 | 192,600 | ||||||
Regulatory liabilities | 42,946 | 43,064 | ||||||
Environmental liabilities | 8,843 | 8,942 | ||||||
Other pension and benefit costs | 32,848 | 33,481 | ||||||
Deferred investment tax credits and other liabilities | 2,628 | 2,597 | ||||||
Total deferred credits and other liabilities | 284,681 | 280,684 | ||||||
Other commitments and contingencies (Note 6) | ||||||||
Total Capitalization and Liabilities | $ | 1,081,984 | $ | 1,067,421 | ||||
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, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Operating Activities | ||||||||
Net income | $ | 20,367 | $ | 21,109 | ||||
Adjustments to reconcile net income to net cash provided by operating activities: | ||||||||
Depreciation and amortization | 7,503 | 6,975 | ||||||
Depreciation and accretion included in other costs | 1,646 | 1,689 | ||||||
Deferred income taxes, net | 4,326 | (496 | ) | |||||
Realized (gain) loss on commodity contracts/sale of assets/investments | 479 | (840 | ) | |||||
Unrealized loss on investments/commodity contracts | 18 | 21 | ||||||
Employee benefits and compensation | 380 | 300 | ||||||
Share-based compensation | 649 | 537 | ||||||
Other, net | 24 | 4 | ||||||
Changes in assets and liabilities: | ||||||||
Accounts receivable and accrued revenue | (3,738 | ) | (8,014 | ) | ||||
Propane inventory, storage gas and other inventory | 3,073 | 5,337 | ||||||
Regulatory assets/liabilities, net | 3,941 | 16,507 | ||||||
Prepaid expenses and other current assets | 1,358 | 2,500 | ||||||
Accounts payable and other accrued liabilities | (1,604 | ) | 350 | |||||
Income taxes receivable | 8,841 | 21,753 | ||||||
Customer deposits and refunds | (134 | ) | (2,890 | ) | ||||
Accrued compensation | (5,943 | ) | (5,262 | ) | ||||
Other assets and liabilities, net | 1,242 | 2,753 | ||||||
Net cash provided by operating activities | 42,428 | 62,333 | ||||||
Investing Activities | ||||||||
Property, plant and equipment expenditures | (36,847 | ) | (25,482 | ) | ||||
Proceeds from sales of assets | 51 | 198 | ||||||
Environmental expenditures | (99 | ) | (49 | ) | ||||
Net cash used in investing activities | (36,895 | ) | (25,333 | ) | ||||
Financing Activities | ||||||||
Common stock dividends | (4,204 | ) | (3,763 | ) | ||||
Issuance of stock for Dividend Reinvestment Plan | 195 | 217 | ||||||
Change in cash overdrafts due to outstanding checks | (1,501 | ) | (2,191 | ) | ||||
Net borrowing (repayment) under line of credit agreements | 839 | (19,269 | ) | |||||
Repayment of long-term debt and capital lease obligation | (402 | ) | (398 | ) | ||||
Net cash used in financing activities | (5,073 | ) | (25,404 | ) | ||||
Net Increase in Cash and Cash Equivalents | 460 | 11,596 | ||||||
Cash and Cash Equivalents—Beginning of Period | 2,855 | 4,574 | ||||||
Cash and Cash Equivalents—End of Period | $ | 3,315 | $ | 16,170 | ||||
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 | ||||||||||||||||||||||||||||||
(in thousands, except shares and per share data) | Number of Shares(1) | Par Value | Additional Paid-In Capital | Retained Earnings | Accumulated Other Comprehensive Loss | Deferred Compensation | Treasury Stock | Total | ||||||||||||||||||||||
Balance at December 31, 2014 | 14,588,711 | $ | 7,100 | $ | 156,581 | $ | 142,317 | $ | (5,676 | ) | $ | 1,258 | $ | (1,258 | ) | $ | 300,322 | |||||||||||||
Net income | — | — | 41,140 | — | — | — | 41,140 | |||||||||||||||||||||||
Other comprehensive loss | — | — | — | — | (164 | ) | — | — | (164 | ) | ||||||||||||||||||||
Dividend declared ($1.1325 per share) | — | — | — | (17,222 | ) | — | — | — | (17,222 | ) | ||||||||||||||||||||
Retirement savings plan and dividend reinvestment plan | 43,275 | 21 | 2,214 | — | — | — | — | 2,235 | ||||||||||||||||||||||
Common stock issued in acquisition | 592,970 | 289 | 29,876 | 30,165 | ||||||||||||||||||||||||||
Share-based compensation and tax benefit (2) (3) | 45,703 | 22 | 1,640 | — | — | — | — | 1,662 | ||||||||||||||||||||||
Treasury stock activities | — | — | — | — | — | 625 | (625 | ) | — | |||||||||||||||||||||
Balance at December 31, 2015 | 15,270,659 | 7,432 | 190,311 | 166,235 | (5,840 | ) | 1,883 | (1,883 | ) | 358,138 | ||||||||||||||||||||
Net income | — | — | — | 20,367 | — | — | — | 20,367 | ||||||||||||||||||||||
Other comprehensive income | — | — | — | — | 89 | — | — | 89 | ||||||||||||||||||||||
Dividend declared ($0.2875 per share) and dividend reinvestment plan | 6,787 | 3 | 377 | (4,437 | ) | — | — | — | (4,057 | ) | ||||||||||||||||||||
Share-based compensation and tax benefit (3) | 27,522 | 14 | (299 | ) | — | — | — | — | (285 | ) | ||||||||||||||||||||
Treasury stock activities | — | — | — | — | — | 338 | (338 | ) | — | |||||||||||||||||||||
Balance at March 31, 2016 | 15,304,968 | $ | 7,449 | $ | 190,389 | $ | 182,165 | $ | (5,751 | ) | $ | 2,221 | $ | (2,221 | ) | $ | 374,252 | |||||||||||||
(1) | Includes 75,959 and 70,631 shares at March 31, 2016 and December 31, 2015, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan. |
(2) | Includes amounts for shares issued for Directors’ compensation. |
(3) | The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended March 31, 2016, and for the year ended December 31, 2015, we withheld 12,031 and 12,620 shares, respectively, for taxes. |
The accompanying notes are an integral part of these financial statements.
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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, 2015. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.
Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.
We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015 and condensed consolidated statement of cash flows for the three months ended March 31, 2015 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.
FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $323,000 and $333,000 at March 31, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets.
Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter.
Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations.
Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations.
Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1,
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2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet, by eliminating the current deferred income taxes asset and decreasing noncurrent deferred income taxes liability by $831,000.
Recent Accounting Standards Yet to be Adopted
Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations.
Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations.
Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations.
Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.
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2. | Calculation of Earnings Per Share |
Three Months Ended | ||||||||
March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands, except shares and per share data) | ||||||||
Calculation of Basic Earnings Per Share: | ||||||||
Net Income | $ | 20,367 | $ | 21,109 | ||||
Weighted average shares outstanding | 15,286,842 | 14,604,841 | ||||||
Basic Earnings Per Share | $ | 1.33 | $ | 1.45 | ||||
Calculation of Diluted Earnings Per Share: | ||||||||
Reconciliation of Numerator: | ||||||||
Net Income | $ | 20,367 | $ | 21,109 | ||||
Reconciliation of Denominator: | ||||||||
Weighted shares outstanding—Basic | 15,286,842 | 14,604,841 | ||||||
Effect of dilutive securities: | ||||||||
Share-based compensation | 45,070 | 51,469 | ||||||
Adjusted denominator—Diluted | 15,331,912 | 14,656,310 | ||||||
Diluted Earnings Per Share | $ | 1.33 | $ | 1.44 | ||||
3. | Acquisitions |
Gatherco Acquisition
On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio. The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative which together serve more than 20,000 end-use customers. Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services necessary to maintain quality and reliability to its wholesale markets.
At closing, we issued 592,970 shares of our common stock, valued at $30.2 million based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.
(in thousands) | Net Purchase Price | ||
Chesapeake Utilities common stock | $ | 30,164 | |
Cash | 27,494 | ||
Acquired debt | 1,696 | ||
Aggregate amount paid in the acquisition | 59,354 | ||
Less: cash acquired | (6,806 | ) | |
Net amount paid in the acquisition | $ | 52,548 | |
The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities over five years.
We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed during 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this acquisition for the three months ended March 31, 2016, included in our condensed consolidated statements of income, were $7.9 million and $1.7 million, respectively. This acquisition was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share.
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The purchase price allocation of the Gatherco acquisition is as follows:
Purchase price | |||
(in thousands) | Allocation | ||
Purchase price | $ | 57,658 | |
Property plant and equipment | 53,203 | ||
Cash | 6,806 | ||
Accounts receivable | 3,629 | ||
Income taxes receivable | 3,163 | ||
Other assets | 425 | ||
Total assets acquired | 67,226 | ||
Long-term debt | 1,696 | ||
Deferred income taxes | 13,409 | ||
Accounts payable | 3,837 | ||
Other current liabilities | 745 | ||
Total liabilities assumed | 19,687 | ||
Net identifiable assets acquired | 47,539 | ||
Goodwill | $ | 10,119 | |
The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the acquisition date. The goodwill reflects the value paid primarily for opportunities for growth in a new, strategic geographic area. All of the goodwill from this acquisition was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes.
In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to $10.1 million after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.
Other acquisitions
On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000. In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three months ended March 31, 2016 were not material.
4. | Rates and Other Regulatory Activities |
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.
Delaware
Rate Case Filing: On December 21, 2015, our Delaware division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the fourth quarter of 2016. Pending the decision, the Delaware division increased rates on an interim
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basis by $2.5 million effective February 19, 2016. These rates, which are subject to refund, represent a five percent increase over current rates.
Maryland
Sandpiper Rate Case Filing: On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $950,000, or five percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue-decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the third quarter of 2016.
Florida
On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time.
On February 2, 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held April 5, 2016.
Eastern Shore
White Oak Mainline Expansion Project: On November 21, 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 industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. On January 22, 2015, the FERC issued a notice of intent to prepare an environmental assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville, Pennsylvania Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, the FERC requested that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, the FERC issued a 30-day public scoping notice in advance of issuing an environmental assessment in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop.
On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route. On February 10, 2016 the FERC issued a notice to prepare an environmental assessment and will combine both the White Oak Mainline Expansion project and System Reliability Project into a single assessment. The environmental assessment was issued on April 25, 2016, with the FERC's 90-day authorization decision to be issued on July 24, 2016.
On March 28, 2016, subsequent to the issuance of the schedule, FERC issued another environmental data request concerning the United States Department of Agriculture and an agricultural conservation easement on a tract of land where the White Oak Mainline Project would install a portion of the pipeline in its existing right-of way. On April 4, 2016, Eastern Shore responded to the data request.
System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project.
On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Two interested parties filed comments and protests with the FERC. Eastern Shore has filed answers to the comments and protests from the two parties.
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On September 4, 2015, the FERC issued a notice of intent to prepare an environmental assessment, and Eastern Shore responded to the FERC Staff's environmental data requests. On February 10, 2016, the FERC issued a notice combining the System Reliability Project and White Oak Mainline Expansion project into a single environmental assessment. On March 2, 2016, the FERC issued a revised notice rescheduling the issuance of the combined environmental assessment to April 25, 2016, with the 90-day authorization decision to be issued on July 24, 2016.
TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.
5. Environmental Commitments and Contingencies
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate at current and former operating sites the effect on the environment of the disposal or release of specified substances.
MGP Sites
We have participated in the investigation, assessment or remediation of, and have exposures at seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.
As of March 31, 2016, we had approximately $10.0 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $10.2 million of which has been recovered as of March 31, 2016, leaving approximately $3.8 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had $353,000 in environmental liabilities at March 31, 2016 related to Chesapeake Utilities' MGP sites in Salisbury, Maryland and Winter Haven, Florida, representing our estimate of future costs associated with these sites. As of March 31, 2016, we had approximately $58,000 in regulatory and other assets for future recovery through Chesapeake Utilities' rates.
During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of March 31, 2016, we had approximately $186,000 in environmental liabilities and $269,000 in regulatory and other assets related to this site.
Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.
West Palm Beach, Florida
Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. A letter dated January 6, 2016, was received from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.
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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. We continue to expect that all costs related to these activities will be recoverable from customers through rates.
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, 2016, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remedial construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.
As of March 31, 2016, 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 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 under the Third Participation Agreement. No such claims have been made as of March 31, 2016.
Key West, Florida
FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual monitoring program. The most recent groundwater-monitoring event was conducted in March of 2016. Natural Attenuation Default criteria were met at all locations sampled.
Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.
Pensacola, Florida
FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000
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Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.
Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.
Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates.
FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP. Therefore, we have not recorded a liability for sediment remediation.
Salisbury, Maryland
We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.
Seaford, Delaware
In a letter dated December 5, 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, the DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to the DNREC on April 2, 2015, which was approved on September 17, 2015, to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and a draft remedial investigation report was submitted to the DNREC on March 7, 2016. We anticipate submitting the final report, based on comments from the DNREC during the second quarter of 2016. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000. We also believe these costs will be recoverable from customers through rates.
Cambridge, Maryland
We are discussing with the MDE a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.
Ohio
We have also completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. The costs incurred to date associated with remediation activities for these facilities, is approximately $1.4 million. Pursuant to the merger agreement, an escrow was established to fund certain claims by Chesapeake Utilities and Aspire Energy for indemnification by Gatherco, including environmental claims. Gatherco's indemnification obligations for environmental matters apply to remediation costs in excess of $431,250 and are capped at $1.7 million. We have submitted our request for reimbursement to the escrow agent.
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6. | Other Commitments and Contingencies |
Natural Gas, Electric and Propane Supply
Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2017.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately three years remain under this contract. Sandpiper's current annual commitment is estimated at approximately 6.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term. Approximately three years remain under this contract. Sharp's current annual commitment is estimated at approximately 6.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
Chesapeake Utilities' Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay the capacity charge.
In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total monthly purchase commitment ranges from 9,982 to 13,423 Dts/d for a one-year term. PESCO is obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2016, FPU was in compliance with all of the requirements of its fuel supply contracts.
Corporate Guarantees
The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $65.0 million.
We have issued corporate guarantees to certain vendors of our subsidiaries, 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, 2016 was $48.7 million, with the guarantees expiring on various dates through March 2017.
Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, for further details).
We issued letters of credit totaling $8.1 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and to our
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current and previous primary insurance carriers. These letters of credit have various expiration dates through March 2017. There have been no draws on these letters of credit as of March 31, 2016. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of March 31, 2016, we maintained a liability of $50,000 related to unrecognized income tax benefits and $196,000 related to contingencies for taxes other than income. As of December 31, 2015, we maintained a liability of $50,000 related to unrecognized income tax benefits and $310,000 related to contingencies for taxes other than income.
Other
We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.
7. | Segment Information |
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise two reportable segments:
• | Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore. |
• | Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy, whose services include natural gas gathering, processing, transportation and supply (See Note 3, Acquisitions, regarding the acquisition of Gatherco). Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services. |
The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.
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The following table presents financial information about our reportable segments:
Three Months Ended | ||||||||
March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Operating Revenues, Unaffiliated Customers | ||||||||
Regulated Energy segment | $ | 88,894 | $ | 109,292 | ||||
Unregulated Energy segment | 57,402 | 60,789 | ||||||
Total operating revenues, unaffiliated customers | $ | 146,296 | $ | 170,081 | ||||
Intersegment Revenues (1) | ||||||||
Regulated Energy segment | $ | 322 | $ | 290 | ||||
Unregulated Energy segment | 113 | 207 | ||||||
Other businesses | 226 | 221 | ||||||
Total intersegment revenues | $ | 661 | $ | 718 | ||||
Operating Income | ||||||||
Regulated Energy segment | $ | 24,319 | $ | 22,182 | ||||
Unregulated Energy segment | 11,936 | 15,229 | ||||||
Other businesses and eliminations | 125 | 97 | ||||||
Total operating income | 36,380 | 37,508 | ||||||
Other (Expense) income, net | (34 | ) | 133 | |||||
Interest | 2,650 | 2,448 | ||||||
Income before Income Taxes | 33,696 | 35,193 | ||||||
Income taxes | 13,329 | 14,084 | ||||||
Net Income | $ | 20,367 | $ | 21,109 | ||||
(1) | All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. |
(in thousands) | March 31, 2016 | December 31, 2015 | ||||||
Identifiable Assets | ||||||||
Regulated Energy segment | $ | 879,878 | $ | 872,065 | ||||
Unregulated Energy segment | 178,723 | 171,840 | ||||||
Other businesses and eliminations | 23,383 | 23,516 | ||||||
Total identifiable assets | $ | 1,081,984 | $ | 1,067,421 | ||||
Our operations are entirely domestic.
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8. | Accumulated Other Comprehensive Loss |
Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015. All amounts are presented net of tax.
Defined Benefit | Commodity | |||||||||||
Pension and | Contracts | |||||||||||
Postretirement | Cash Flow | |||||||||||
Plan Items | Hedges | Total | ||||||||||
(in thousands) | ||||||||||||
As of December 31, 2015 | $ | (5,580 | ) | $ | (260 | ) | $ | (5,840 | ) | |||
Other comprehensive loss before reclassifications | — | (283 | ) | (283 | ) | |||||||
Amounts reclassified from accumulated other comprehensive loss | 89 | 283 | 372 | |||||||||
Net current-period other comprehensive income | 89 | — | 89 | |||||||||
As of March 31, 2016 | $ | (5,491 | ) | $ | (260 | ) | $ | (5,751 | ) | |||
Defined Benefit | Commodity | |||||||||||
Pension and | Contracts | |||||||||||
Postretirement | Cash Flow | |||||||||||
Plan Items | Hedges | Total | ||||||||||
(in thousands) | ||||||||||||
As of December 31, 2014 | $ | (5,643 | ) | $ | (33 | ) | $ | (5,676 | ) | |||
Other comprehensive loss before reclassifications | — | (7 | ) | (7 | ) | |||||||
Amounts reclassified from accumulated other comprehensive loss | 82 | 33 | 115 | |||||||||
Net prior-period other comprehensive income | 82 | 26 | 108 | |||||||||
As of March 31, 2015 | $ | (5,561 | ) | $ | (7 | ) | $ | (5,568 | ) | |||
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2016 and 2015. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
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Three Months Ended | ||||||||
March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Amortization of defined benefit pension and postretirement plan items: | ||||||||
Prior service cost (1) | $ | 20 | $ | 17 | ||||
Net loss (1) | (168 | ) | (154 | ) | ||||
Total before income taxes | (148 | ) | (137 | ) | ||||
Income tax benefit | 59 | 55 | ||||||
Net of tax | $ | (89 | ) | $ | (82 | ) | ||
Gains and losses on commodity contracts cash flow hedges | ||||||||
Propane swap agreements (2) | $ | (322 | ) | $ | — | |||
Call options (2) | — | (55 | ) | |||||
Natural gas futures (2) | (149 | ) | — | |||||
Total before income taxes | (471 | ) | (55 | ) | ||||
Income tax benefit | 188 | 22 | ||||||
Net of tax | (283 | ) | (33 | ) | ||||
Total reclassifications for the period | $ | (372 | ) | $ | (115 | ) | ||
(1) These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.
Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements and call options are included in cost of sales in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.
9. | Employee Benefit Plans |
Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2016 and 2015 are set forth in the following table:
Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | ||||||||||||||||||||||||||||||||||||
For the Three Months Ended March 31, | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | 2016 | 2015 | ||||||||||||||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||||||||||||||||||
Interest cost | $ | 105 | $ | 102 | $ | 630 | $ | 626 | $ | 23 | $ | 23 | $ | 11 | $ | 11 | $ | 14 | $ | 15 | ||||||||||||||||||||
Expected return on plan assets | (131 | ) | (135 | ) | (701 | ) | (777 | ) | — | — | — | — | — | — | ||||||||||||||||||||||||||
Amortization of prior service cost | — | — | — | — | — | 2 | (20 | ) | (19 | ) | — | — | ||||||||||||||||||||||||||||
Amortization of net loss | 104 | 90 | 128 | 114 | 22 | 25 | 18 | 17 | — | 2 | ||||||||||||||||||||||||||||||
Net periodic cost (benefit) | 78 | 57 | 57 | (37 | ) | 45 | 50 | 9 | 9 | 14 | 17 | |||||||||||||||||||||||||||||
Amortization of pre-merger regulatory asset | — | — | 191 | 190 | — | — | — | — | 2 | 2 | ||||||||||||||||||||||||||||||
Total periodic cost | $ | 78 | $ | 57 | $ | 248 | $ | 153 | $ | 45 | $ | 50 | $ | 9 | $ | 9 | $ | 16 | $ | 19 | ||||||||||||||||||||
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We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2016. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations 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 $2.7 million and $2.8 million at March 31, 2016 and December 31, 2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of $802,000, which will increase our total expected benefit costs to $1.6 million.
Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss. The following table presents 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, 2016 and 2015:
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 cost (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 | |||||||||||
For the Three Months Ended March 31, 2015 | Chesapeake Pension Plan | FPU Pension Plan | Chesapeake SERP | Chesapeake Postretirement Plan | FPU Medical Plan | Total | ||||||||||||||||||
(in thousands) | ||||||||||||||||||||||||
Prior service cost (credit) | $ | — | $ | — | $ | 2 | $ | (19 | ) | $ | — | $ | (17 | ) | ||||||||||
Net loss | 90 | 114 | 25 | 17 | 2 | 248 | ||||||||||||||||||
Total recognized in net periodic benefit cost | $ | 90 | $ | 114 | $ | 27 | $ | (2 | ) | $ | 2 | $ | 231 | |||||||||||
Recognized from accumulated other comprehensive loss (1) | $ | 90 | $ | 22 | $ | 27 | $ | (2 | ) | $ | — | $ | 137 | |||||||||||
Recognized from regulatory asset | — | 92 | — | — | 2 | 94 | ||||||||||||||||||
Total | $ | 90 | $ | 114 | $ | 27 | $ | (2 | ) | $ | 2 | $ | 231 | |||||||||||
(1) | See Note 8, Accumulated Other Comprehensive Loss. |
During the three months ended March 31, 2016, we contributed $104,000 to the Chesapeake Pension Plan and $337,000 to the FPU Pension Plan. We expect to contribute a total of $508,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2016, which represent 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, 2016, were $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2016. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2016, were $21,000. We estimate that approximately $82,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2016. Cash benefits paid under the FPU Medical Plan, primarily for medical claims
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for the three months ended March 31, 2016, were $38,000. We estimate that approximately $149,000 will be paid for such benefits under the FPU Medical Plan in 2016.
10. | Investments |
The investment balances at March 31, 2016 and December 31, 2015, consisted of the following:
(in thousands) | March 31, 2016 | December 31, 2015 | |||||
Rabbi trust (associated with the Deferred Compensation Plan) | $ | 3,654 | $ | 3,626 | |||
Investments in equity securities | 20 | 18 | |||||
Total | $ | 3,674 | $ | 3,644 | |||
We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2016 and 2015, we recorded a net unrealized loss of $18,000 and a net unrealized gain of $104,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the investments in the Rabbi Trust.
11. | 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, 2016 and 2015:
Three Months Ended | ||||||||
March 31, | ||||||||
2016 | 2015 | |||||||
(in thousands) | ||||||||
Awards to non-employee directors | $ | 165 | $ | 150 | ||||
Awards to key employees | 484 | 387 | ||||||
Total compensation expense | 649 | 537 | ||||||
Less: tax benefit | (261 | ) | (217 | ) | ||||
Share-based compensation amounts included in net income | $ | 388 | $ | 320 | ||||
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 2015, each of our non-employee directors received an annual retainer of 1,207 shares of common stock under the SICP for service as a director through the 2016 Annual Meeting of Stockholders. At March 31, 2016, there was $55,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2016.
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Key Employees
The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2016:
Number of Shares | Weighted Average Fair Value | ||||||
Outstanding— December 31, 2015 | 110,398 | $ | 38.34 | ||||
Granted | 46,571 | $ | 61.50 | ||||
Vested | (39,553 | ) | $ | 31.79 | |||
Expired | (2,325 | ) | $ | 42.25 | |||
Outstanding— March 31, 2016 | 115,091 | $ | 49.26 | ||||
In February 2016, our Board of Directors granted awards of 46,571 shares of common stock to key employees under the SICP. The shares granted in February 2016 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2018. 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 March 31, 2016, the aggregate intrinsic value of the SICP awards granted to key employees was $7.2 million. At March 31, 2016, there was $3.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2016 through 2018.
12. | Derivative Instruments |
We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. 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 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, 2016, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Hedging Activities in 2016
Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts expire within two years and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2016, PESCO had a total of 6,723 Dts/d hedged under natural gas futures contracts, with a liability fair value of $423,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain/loss in other comprehensive income (loss).
Hedging Activities in 2015
In March, May and June 2015, Sharp paid a total of $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the 2015-2016 heating season. We exercised the put options as propane prices fell below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. We received $239,000 representing the difference between the market prices and the strike prices during those months. We accounted for the put options as fair value hedges.
In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 per gallon, for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid $484,000,
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representing the difference between the index prices and swap prices during those months of the swap agreements.
Commodity Contracts for Trading Activities
Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statements of income for the period of change. As of March 31, 2016, we had the following outstanding trading contracts, which we accounted for as derivatives:
Quantity in | Estimated Market | Weighted Average | ||||||||
At March 31, 2016 | Gallons | Prices | Contract Prices | |||||||
Forward Contracts | ||||||||||
Sale | 630,000 | $ | 0.4425 | $ | 0.4425 | |||||
Purchase | 631,000 | $ | 0.4413 | $ | 0.4422 | |||||
Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2016.
Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, are as follows:
Asset Derivatives | ||||||||||
Fair Value As Of | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2016 | December 31, 2015 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Forward contracts | Mark-to-market energy assets | $ | — | $ | 1 | |||||
Derivatives designated as fair value hedges | ||||||||||
Put options | Mark-to-market energy assets | 152 | ||||||||
Total asset derivatives | $ | — | $ | 153 | ||||||
Liability Derivatives | ||||||||||
Fair Value As Of | ||||||||||
(in thousands) | Balance Sheet Location | March 31, 2016 | December 31, 2015 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Forward contracts | Mark-to-market energy liabilities | $ | — | $ | 1 | |||||
Derivatives designated as cash flow hedges | ||||||||||
Propane swap agreements | Mark-to-market energy liabilities | — | 323 | |||||||
Natural gas futures contracts | Mark-to-market energy liabilities | 423 | 109 | |||||||
Total liability derivatives | $ | 423 | $ | 433 | ||||||
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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 | 2016 | 2015 | |||||||
Derivatives not designated as hedging instruments | ||||||||||
Realized gain on forward contracts (1) | Revenue | $ | 187 | $ | 277 | |||||
Unrealized gain (loss) on forward contracts (1) | Revenue | 1 | (125 | ) | ||||||
Propane swap agreements | Cost of sales | — | 18 | |||||||
Derivatives designated as fair value hedges | ||||||||||
Put /Call options | Cost of sales | 73 | 506 | |||||||
Put /Call options (2) | Propane Inventory | — | (3 | ) | ||||||
Derivatives designated as cash flow hedges | ||||||||||
Propane swap agreements | Cost of sales | (364 | ) | — | ||||||
Propane swap agreements | Other Comprehensive Loss | — | (12 | ) | ||||||
Call options | Cost of sales | — | (81 | ) | ||||||
Natural gas futures contracts | Cost of sales | 149 | — | |||||||
Natural gas futures contracts | Other Comprehensive Loss | (462 | ) | — | ||||||
Total | $ | (416 | ) | $ | 580 | |||||
(1) | All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income. |
(2) | As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory. |
13. | Fair Value of Financial Instruments |
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
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, 2016 and December 31, 2015:
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Fair Value Measurements Using: | ||||||||||||||||
As of March 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 | $ | 20 | $ | 20 | $ | — | $ | — | ||||||||
Investments—guaranteed income fund | $ | 525 | $ | — | $ | — | $ | 525 | ||||||||
Investments—mutual funds and other | $ | 3,129 | $ | 3,129 | $ | — | $ | — | ||||||||
Mark-to-market energy assets, incl. put options and swap agreements | $ | — | $ | — | $ | — | $ | — | ||||||||
Liabilities: | ||||||||||||||||
Mark-to-market energy liabilities incl. swap agreements | $ | 423 | $ | — | $ | 423 | $ | — | ||||||||
Fair Value Measurements Using: | ||||||||||||||||
As of December 31, 2015 | Fair Value | Quoted- Prices- in Active Markets (Level 1) | ||||||||||||||