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ONDENSED
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INANCIAL
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NAUDITED
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1. Summary of Accounting Policies
Basis of Presentation
References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.
The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended
December 31, 2015
. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.
Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.
We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015. We have revised the condensed consolidated statement of cash flows for the six months ended June 30, 2015 to reflect only property, plant and equipment expenditures paid in cash within the Investing Activities section. The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section. These reclassifications are considered immaterial to the overall presentation of our condensed 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
$312,000
and
$333,000
at June 30, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets.
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, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet by eliminating the current deferred income taxes asset and decreasing the noncurrent deferred income taxes liability by
$831,000
.
Recent Accounting Standards Yet to be Adopted
Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09,
Revenue from Contracts with Customers
. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. 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.
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Calculation of Earnings Per Share
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Three Months Ended
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Six Months Ended
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June 30,
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June 30,
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2016
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2015
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2016
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2015
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(in thousands, except shares and per share data)
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Calculation of Basic Earnings Per Share:
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Net Income
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$
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8,029
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$
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6,294
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$
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28,396
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$
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27,403
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Weighted average shares outstanding
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15,315,020
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15,235,860
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15,300,931
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14,922,094
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Basic Earnings Per Share
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$
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0.52
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$
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0.41
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$
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1.86
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$
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1.84
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Calculation of Diluted Earnings Per Share:
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Reconciliation of Numerator:
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Net Income
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$
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8,029
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$
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6,294
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28,396
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27,403
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Reconciliation of Denominator:
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Weighted shares outstanding—Basic
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15,315,020
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15,235,860
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15,300,931
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14,922,094
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Effect of dilutive securities:
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Share-based compensation
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37,682
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44,797
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41,356
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48,096
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Adjusted denominator—Diluted
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15,352,702
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15,280,657
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15,342,287
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14,970,190
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Diluted Earnings Per Share
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$
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0.52
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$
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0.41
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$
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1.85
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$
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1.83
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Gatherco Merger
On April 1, 2015, we completed the merger in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately
2,500
miles of pipeline systems in
40
counties throughout Ohio. The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative, which together serve more than
20,000
end-use customers. Aspire Energy sources gas primarily from
300
conventional producers. Aspire Energy also provides gathering and processing services 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
$6.8 million
of cash on hand at closing.
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(in thousands)
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Net Purchase Price
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Chesapeake Utilities common stock
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$
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30,164
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Cash
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27,494
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Acquired debt
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1,696
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Aggregate amount paid in the acquisition
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59,354
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Less: cash acquired
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(6,806
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)
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Net amount paid in the acquisition
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$
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52,548
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The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to
$15.0 million
based on a percentage of revenue generated from potential new gathering opportunities during the
five
-year period following the closing. As of June 30, 2016, there have been no related gathering opportunities developed; therefore, no contingent consideration liability has been recorded. Based on the absence of related gathering opportunities being developed as of June 30, 2016, we are unable to estimate the range of undiscounted contingent liability outcomes at this time.
We incurred
$1.3 million
in transaction costs associated with this merger,
$786,000
of which we incurred in 2014, and the remaining
$514,000
we incurred during 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this merger for the three months ended
June 30, 2016
, included in our condensed consolidated statements of income, were
$4.8 million
and
$28,000
, respectively. The revenue and net income from this merger
for the six months ended June 30, 2016
, included in our condensed consolidated statements of income, were
$12.8 million
and
$1.7 million
, respectively. This merger was accretive to earnings per share in the first full year of operations, generating
$0.03
in additional earnings per share.
The purchase price allocation of the Gatherco merger was as follows:
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Purchase price
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(in thousands)
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Allocation
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Purchase price
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$
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57,658
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Property plant and equipment
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53,203
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Cash
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6,806
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Accounts receivable
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3,629
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Income taxes receivable
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3,163
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Other assets
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425
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Total assets acquired
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67,226
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Long-term debt
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1,696
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Deferred income taxes
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13,409
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Accounts payable
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3,837
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Other current liabilities
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745
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Total liabilities assumed
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19,687
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Net identifiable assets acquired
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47,539
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Goodwill
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$
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10,119
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The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the merger date. The goodwill reflects the value paid primarily for opportunities for growth in a new, strategic geographic area. All of the goodwill from this merger was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes.
In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from
$11.1 million
to
$10.1 million
after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.
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4.
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Rates and Other Regulatory Activities
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Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.
Delaware
Rate Case Filing:
On December 21, 2015, our Delaware division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of approximately
$4.7 million
, or nearly
ten percent
, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue normalization mechanism for residential and small commercial customers. We expect a decision on the application during the first quarter of 2017. Pending the decision, our Delaware division increased rates on an interim basis based on the
$2.5 million
annualized interim rates approved by the Delaware PSC,
effective February 19, 2016. We recognized incremental revenue of approximately
$555,000
(
$332,000
net of tax) and
$878,000
(
$526,000
net of tax) for the three and six months ended June 30, 2016, respectively. In addition, our Delaware division requested and received approval on July 26, 2016 from the Delaware PSC to implement revised interim rates of
$4.7 million
annualized for usage on and after August 1, 2016. Revenue collected prior to a final Delaware PSC decision is subject to refund. Although the final decision is expected during the first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast the timing of a final decision. 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 approximately
five percent
, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue normalization mechanism for residential and small commercial customers. The procedural schedule was suspended in early May 2016 to allow for the continuation of settlement discussions between Sandpiper, Maryland PSC Staff and Maryland Office of People's Counsel. We expect a decision on the application 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.
On April 11, 2016, FPU’s natural gas divisions and Chesapeake Utilities' Florida division filed a joint petition for approval to allow FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchased gas adjustment and operational balancing account, which is currently allocated to a limited number of customers. The proposed new allocation of these costs would include additional customers, primarily transportation customers, benefiting from these costs but not currently paying for them. We expect the petition to be approved by the Florida PSC in late 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 electric power generator in Kent County, Delaware. Eastern Shore proposes to construct approximately
7.2
miles of
16
-inch diameter pipeline looping in Chester County, Pennsylvania and
3,550
horsepower of additional compression at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware.
On 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 the evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Historic District of Kemblesville, Pennsylvania. 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 and shortened the total miles of the proposed pipeline to
5.4
miles. On February 10, 2016, the FERC issued a notice combining the White Oak Mainline Expansion Project and the System Reliability Project into a single environmental
assessment. On March 2, 2016, the FERC issued a revised notice, rescheduling the issuance of the combined environmental assessment to April 25, 2016, with a 90-day authorization decision to be issued no later than July 24, 2016.
On March 28, 2016, subsequent to the issuance of the schedule, the 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. Subsequently, Eastern Shore revised the construction workspace configuration to mutual agreement of both parties.
On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed White Oak Mainline Project. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment and requires Eastern Shore to comply with
19
environmental conditions.
System Reliability Project:
On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately
10.1
miles of
16
-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further 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.
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 no later than July 24, 2016. On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. The FERC granted Eastern Shore’s request for a pre-determination of rolled-in rate treatment in its next rate base proceeding and requires Eastern Shore to comply with
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environmental conditions.
TETLP Capacity Expansion Project:
On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by
53,000
Dts/d, for a total capacity of
160,000
Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.
2017 Expansion Project:
On May 12, 2016, Eastern Shore submitted a request to the FERC to initiate the FERC’s pre-filing review procedures for Eastern Shore's 2017 expansion project. The expansion project consists of approximately
33
miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional
3,550
horsepower compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately
17
miles of new mainline extension and two pressure control stations in Sussex County, Delaware. The expansion project is necessary to provide up to
86,437
Dts/d of additional firm natural gas transportation capacity to meet anticipated market demand. On May 17, 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore is currently working through the pre-filing process and anticipates filing a certificate of public convenience and necessity seeking authorization to construct the project in November 2016.
2017 Rate Case Filing
In January 2017, Eastern Shore intends to file a base rate proceeding with the FERC as required by the terms of its 2012 settlement agreement.
5. Environmental Commitments and Contingencies
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances.
MGP Sites
We have participated in the investigation, assessment or remediation of, and have exposures at,
seven
former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.
As of
June 30, 2016
, we had approximately
$9.9 million
in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to
$14.0 million
of its environmental costs related to all of its MGP sites, approximately
$10.3 million
of which has been recovered as of
June 30, 2016
, leaving approximately
$3.7 million
in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had
$314,000
in environmental liabilities at
June 30, 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
June 30, 2016
, we had approximately
$29,000
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
June 30, 2016
, we had approximately
$177,000
in environmental liabilities and
$268,000
in regulatory and other assets related to this site.
Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.
West Palm Beach, Florida
Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. We received a letter dated January 6, 2016 from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.
We expect that similar remedial actions will ultimately be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately
$4.5 million
to
$15.4 million
, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties. 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 this former MGP site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at
five percent
of a maximum of
$13.0 million
, or
$650,000
. As of
June 30, 2016
, FPU has paid
$650,000
to the Sanford Group escrow account for its entire share of the funding requirements.
In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remedial construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over
$20.0 million
, which includes long-term monitoring and the settlement of claims asserted by
two
adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation.
In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU advised the other members of the Sanford Group that it is unwilling to pay any sum in excess of the
$650,000
committed by FPU in the Third Participation Agreement. The Sanford Group has not requested that FPU contribute to costs beyond the originally agreed upon
$650,000
contribution.
As of
June 30, 2016
, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be
$24,000
. We are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense as to its limited liability for future costs exceeding
$13.0 million
to implement the final remedy for this site, as provided for in the Third Participation Agreement, or whether the other members of the Sanford Group will pursue a claim against FPU for a sum in excess of the
$650,000
that FPU has paid pursuant to the Third Participation Agreement. No such claims have been made as of
June 30, 2016
.
Key West, Florida
FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after
17 years
of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual NAM. The most recent groundwater-monitoring event was conducted in March 2016. Natural attenuation default criteria were met at all locations sampled and the semi-annual report was submitted on April 18, 2016. FDEP responded with an acceptance letter on April 22, 2016, concurring with FPU’s consultant’s recommendation that semi-annual monitoring should continue at this facility, with the next semi-annual NAM scheduled for the third quarter of 2016.
Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed
$50,000
. The annual cost to conduct the limited NAM program is not expected to exceed
$8,000
.
Pensacola, Florida
FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed
$5,000
.
Winter Haven, Florida
The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.
Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.
Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed
$425,000
, which includes an estimate of
$100,000
to implement additional actions, such as institutional controls, at the site. 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, DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. On September 17, 2015, DNREC approved our application to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and the resulting remedial investigation report was submitted to DNREC in May 2016. Based on findings from the remedial investigation, DNREC requested additional investigative work be performed prior to approval of potential remedial actions. We anticipate completing this additional investigative work by the end of 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 completed the investigation, assessment and remediation of
eight
natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. Gatherco's indemnification obligations for environmental matters apply to remediation costs in excess of a
$431,250
deductible and are capped at
$1.7 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. The costs incurred to date associated with remediation activities for these eight facilities is approximately
$1.6 million
. We have recorded a receivable for the costs incurred, net of the deductible amount, and have submitted our request for reimbursement to the escrow agent. Negotiations are currently underway.
|
|
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, or until May 2019. Sandpiper's current annual commitment is estimated at approximately
6.5 million
gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a
six
-year term, or until May 2019. Sharp's current annual commitment is estimated at approximately
6.5 million
gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
Chesapeake Utilities' Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge.
In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers for a one-year term, expiring May 2016, with the total monthly purchase commitment ranging from
9,982
to
13,423
Dts/d. PESCO has renewed these contracts for an additional six-month term, expiring October 2016.
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
June 30, 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 and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is
$65.0 million
.
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
June 30, 2016
was approximately
$53.6 million
, with the guarantees expiring on various dates through
June 2017
.
Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14
, Long-Term Debt
, for further details).
We issued letters of credit totaling approximately
$8.1 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 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
June 30, 2016
. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of
June 30, 2016
, we maintained a liability of approximately
$50,000
related to unrecognized income tax benefits and approximately
$72,000
related to contingencies for taxes other than income. As of
December 31, 2015
, we maintained a liability of approximately
$50,000
related to unrecognized income tax benefits and approximately $
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.
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations comprise two reportable segments:
|
|
•
|
Regulated Energy
. The Regulated Energy segment includes natural gas distribution, natural gas transmission and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
|
|
|
•
|
Unregulated Energy.
The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy, whose services include natural gas gathering, processing, transportation and supply (See Note 3,
Acquisitions
, regarding the merger with Gatherco). 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.
The following table presents financial information about our reportable segments:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
(in thousands)
|
|
|
|
|
|
|
|
|
Operating Revenues, Unaffiliated Customers
|
|
|
|
|
|
|
|
|
Regulated Energy segment
|
|
$
|
66,590
|
|
|
$
|
61,790
|
|
|
$
|
155,483
|
|
|
$
|
171,082
|
|
Unregulated Energy segment
|
|
35,752
|
|
|
30,892
|
|
|
93,155
|
|
|
91,681
|
|
Total operating revenues, unaffiliated customers
|
|
$
|
102,342
|
|
|
$
|
92,682
|
|
|
$
|
248,638
|
|
|
$
|
262,763
|
|
Intersegment Revenues
(1)
|
|
|
|
|
|
|
|
|
Regulated Energy segment
|
|
$
|
805
|
|
|
$
|
270
|
|
|
$
|
1,128
|
|
|
$
|
560
|
|
Unregulated Energy segment
|
|
1,052
|
|
|
1,666
|
|
|
1,165
|
|
|
1,873
|
|
Other businesses
|
|
240
|
|
|
220
|
|
|
466
|
|
|
440
|
|
Total intersegment revenues
|
|
$
|
2,097
|
|
|
$
|
2,156
|
|
|
$
|
2,759
|
|
|
$
|
2,873
|
|
Operating Income
|
|
|
|
|
|
|
|
|
Regulated Energy segment
|
|
$
|
15,226
|
|
|
$
|
13,605
|
|
|
$
|
39,545
|
|
|
$
|
35,788
|
|
Unregulated Energy segment
|
|
412
|
|
|
(540
|
)
|
|
12,347
|
|
|
14,689
|
|
Other businesses and eliminations
|
|
104
|
|
|
105
|
|
|
230
|
|
|
201
|
|
Total operating income
|
|
15,742
|
|
|
13,170
|
|
|
52,122
|
|
|
50,678
|
|
Other Expense, net
|
|
(8
|
)
|
|
(171
|
)
|
|
(42
|
)
|
|
(38
|
)
|
Interest
|
|
2,624
|
|
|
2,485
|
|
|
5,274
|
|
|
4,933
|
|
Income before Income Taxes
|
|
13,110
|
|
|
10,514
|
|
|
46,806
|
|
|
45,707
|
|
Income taxes
|
|
5,081
|
|
|
4,220
|
|
|
18,410
|
|
|
18,304
|
|
Net Income
|
|
$
|
8,029
|
|
|
$
|
6,294
|
|
|
$
|
28,396
|
|
|
$
|
27,403
|
|
|
|
(1)
|
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
June 30, 2016
|
|
December 31, 2015
|
Identifiable Assets
|
|
|
|
|
Regulated Energy segment
|
|
$
|
892,513
|
|
|
$
|
872,065
|
|
Unregulated Energy segment
|
|
192,654
|
|
|
171,840
|
|
Other businesses and eliminations
|
|
11,880
|
|
|
23,516
|
|
Total identifiable assets
|
|
$
|
1,097,047
|
|
|
$
|
1,067,421
|
|
Our operations are entirely domestic.
|
|
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 six months ended
June 30, 2016
and
2015
. All amounts are presented net of tax.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
|
|
Commodity
|
|
|
|
|
Pension and
|
|
Contracts
|
|
|
|
|
Postretirement
|
|
Cash Flow
|
|
|
|
|
Plan Items
|
|
Hedges
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
As of December 31, 2015
|
|
$
|
(5,580
|
)
|
|
$
|
(260
|
)
|
|
$
|
(5,840
|
)
|
Other comprehensive gain before reclassifications
|
|
—
|
|
|
525
|
|
|
525
|
|
Amounts reclassified from accumulated other comprehensive loss
|
|
176
|
|
|
(29
|
)
|
|
147
|
|
Net current-period other comprehensive income
|
|
176
|
|
|
496
|
|
|
672
|
|
As of June 30, 2016
|
|
$
|
(5,404
|
)
|
|
$
|
236
|
|
|
$
|
(5,168
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
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
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
Amounts reclassified from accumulated other comprehensive loss
|
|
165
|
|
|
33
|
|
|
198
|
|
Net prior-period other comprehensive income
|
|
165
|
|
|
32
|
|
|
197
|
|
As of June 30, 2015
|
|
$
|
(5,478
|
)
|
|
$
|
(1
|
)
|
|
$
|
(5,479
|
)
|
The following table presents amounts reclassified out of accumulated other comprehensive loss
for the three and six months ended
June 30, 2016
and
2015
. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
(in thousands)
|
|
|
|
|
|
|
|
|
Amortization of defined benefit pension and postretirement plan items:
|
|
|
|
|
|
|
|
|
Prior service cost
(1)
|
|
$
|
20
|
|
|
$
|
17
|
|
|
$
|
40
|
|
|
$
|
34
|
|
Net loss
(1)
|
|
(166
|
)
|
|
(155
|
)
|
|
(333
|
)
|
|
(310
|
)
|
Total before income taxes
|
|
(146
|
)
|
|
(138
|
)
|
|
(293
|
)
|
|
(276
|
)
|
Income tax benefit
|
|
58
|
|
|
55
|
|
|
117
|
|
|
111
|
|
Net of tax
|
|
$
|
(88
|
)
|
|
$
|
(83
|
)
|
|
$
|
(176
|
)
|
|
$
|
(165
|
)
|
|
|
|
|
|
|
|
|
|
Gains and losses on commodity contracts cash flow hedges
|
|
|
|
|
|
|
|
|
Propane swap agreements
(2)
|
|
$
|
—
|
|
|
$
|
(10
|
)
|
|
$
|
(322
|
)
|
|
$
|
2
|
|
Call options
(2)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(55
|
)
|
Natural gas futures
(2)
|
|
211
|
|
|
—
|
|
|
359
|
|
|
—
|
|
Total before income taxes
|
|
211
|
|
|
(10
|
)
|
|
37
|
|
|
(53
|
)
|
Income tax benefit (expense)
|
|
(81
|
)
|
|
4
|
|
|
(8
|
)
|
|
21
|
|
Net of tax
|
|
130
|
|
|
(6
|
)
|
|
29
|
|
|
(32
|
)
|
Total reclassifications for the period
|
|
$
|
42
|
|
|
$
|
(89
|
)
|
|
$
|
(147
|
)
|
|
$
|
(197
|
)
|
(1)
These amounts are included in the computation of net periodic costs (benefits). See Note 9
, Employee Benefit Plans
, for additional details.
(2)
These amounts are included in the effects of gains and losses from derivative instruments. See Note 12,
Derivative Instruments
, for additional details.
Amortization of defined benefit pension and postretirement plan items is included in operations expense, and gains and losses on propane swap agreements and call options are included in cost of sales in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.
|
|
9.
|
Employee Benefit Plans
|
Net periodic benefit costs for our pension and post-retirement benefits plans
for the three and six months ended
June 30, 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 June 30,
|
|
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
|
|
103
|
|
|
91
|
|
|
128
|
|
|
114
|
|
|
22
|
|
|
25
|
|
|
17
|
|
|
17
|
|
|
—
|
|
|
2
|
|
Net periodic cost (benefit)
|
|
77
|
|
|
58
|
|
|
57
|
|
|
(37
|
)
|
|
45
|
|
|
50
|
|
|
8
|
|
|
9
|
|
|
14
|
|
|
17
|
|
Amortization of pre-merger regulatory asset
|
|
—
|
|
|
—
|
|
|
191
|
|
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
Total periodic cost
|
|
$
|
77
|
|
|
$
|
58
|
|
|
$
|
248
|
|
|
$
|
154
|
|
|
$
|
45
|
|
|
$
|
50
|
|
|
$
|
8
|
|
|
$
|
9
|
|
|
$
|
16
|
|
|
$
|
19
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake
Pension Plan
|
|
FPU
Pension Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
For the Six Months Ended June 30,
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
$
|
210
|
|
|
$
|
204
|
|
|
$
|
1,259
|
|
|
$
|
1,251
|
|
|
$
|
46
|
|
|
$
|
46
|
|
|
$
|
21
|
|
|
$
|
22
|
|
|
$
|
28
|
|
|
$
|
30
|
|
Expected return on plan assets
|
|
(261
|
)
|
|
(270
|
)
|
|
(1,402
|
)
|
|
(1,554
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
(40
|
)
|
|
(39
|
)
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
|
206
|
|
|
181
|
|
|
257
|
|
|
227
|
|
|
44
|
|
|
50
|
|
|
34
|
|
|
35
|
|
|
—
|
|
|
3
|
|
Net periodic cost (benefit)
|
|
155
|
|
|
115
|
|
|
114
|
|
|
(76
|
)
|
|
90
|
|
|
101
|
|
|
15
|
|
|
18
|
|
|
28
|
|
|
33
|
|
Amortization of pre-merger regulatory asset
|
|
—
|
|
|
—
|
|
|
381
|
|
|
381
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
Total periodic cost
|
|
$
|
155
|
|
|
$
|
115
|
|
|
$
|
495
|
|
|
$
|
305
|
|
|
$
|
90
|
|
|
$
|
101
|
|
|
$
|
15
|
|
|
$
|
18
|
|
|
$
|
32
|
|
|
$
|
37
|
|
We expect to record pension and postretirement benefit costs of approximately
$1.6 million
for 2016. Included in these costs is approximately
$769,000
related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately
$2.5 million
and approximately
$2.9 million
at
June 30, 2016
and
December 31, 2015
, respectively. The amortization included in pension expense is also being added to a net periodic loss of approximately
$802,000
, which will increase our total expected benefit costs to approximately
$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 and six months ended
June 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2016
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service credit
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(20
|
)
|
|
$
|
—
|
|
|
$
|
(20
|
)
|
Net loss
|
|
103
|
|
|
128
|
|
|
22
|
|
|
17
|
|
|
—
|
|
|
270
|
|
Total recognized in net periodic benefit cost
|
|
$
|
103
|
|
|
$
|
128
|
|
|
$
|
22
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
250
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
103
|
|
|
$
|
24
|
|
|
$
|
22
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
146
|
|
Recognized from regulatory asset
|
|
—
|
|
|
104
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
104
|
|
Total
|
|
$
|
103
|
|
|
$
|
128
|
|
|
$
|
22
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
250
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 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
|
|
91
|
|
|
114
|
|
|
25
|
|
|
17
|
|
|
2
|
|
|
249
|
|
Total recognized in net periodic benefit cost
|
|
$
|
91
|
|
|
$
|
114
|
|
|
$
|
27
|
|
|
$
|
(2
|
)
|
|
$
|
2
|
|
|
$
|
232
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
91
|
|
|
$
|
22
|
|
|
$
|
27
|
|
|
$
|
(2
|
)
|
|
$
|
—
|
|
|
$
|
138
|
|
Recognized from regulatory asset
|
|
—
|
|
|
92
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
94
|
|
Total
|
|
$
|
91
|
|
|
$
|
114
|
|
|
$
|
27
|
|
|
$
|
(2
|
)
|
|
$
|
2
|
|
|
$
|
232
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2016
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service credit
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
(40
|
)
|
|
$
|
—
|
|
|
$
|
(40
|
)
|
Net loss
|
|
206
|
|
|
257
|
|
|
44
|
|
|
34
|
|
|
—
|
|
|
$
|
541
|
|
Total recognized in net periodic benefit cost
|
|
$
|
206
|
|
|
$
|
257
|
|
|
$
|
44
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
501
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
206
|
|
|
$
|
49
|
|
|
$
|
44
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
293
|
|
Recognized from regulatory asset
|
|
—
|
|
|
208
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
208
|
|
Total
|
|
$
|
206
|
|
|
$
|
257
|
|
|
$
|
44
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
501
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2015
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
(39
|
)
|
|
$
|
—
|
|
|
$
|
(34
|
)
|
Net loss
|
|
181
|
|
|
227
|
|
|
50
|
|
|
35
|
|
|
3
|
|
|
496
|
|
Total recognized in net periodic benefit cost
|
|
$
|
181
|
|
|
$
|
227
|
|
|
$
|
55
|
|
|
$
|
(4
|
)
|
|
$
|
3
|
|
|
$
|
462
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
181
|
|
|
$
|
43
|
|
|
$
|
55
|
|
|
$
|
(4
|
)
|
|
$
|
1
|
|
|
$
|
276
|
|
Recognized from regulatory asset
|
|
—
|
|
|
184
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
186
|
|
Total
|
|
$
|
181
|
|
|
$
|
227
|
|
|
$
|
55
|
|
|
$
|
(4
|
)
|
|
$
|
3
|
|
|
$
|
462
|
|
|
|
(1)
|
See Note 8
, Accumulated Other Comprehensive Loss
.
|
During the
three and six months
ended
June 30, 2016
, we contributed approximately
$170,000
and
$274,000
, respectively, to the Chesapeake Pension Plan and approximately
$548,000
and approximately
$885,000
, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately
$508,000
and approximately
$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 and six months
ended
June 30, 2016
, were approximately
$38,000
and approximately
$76,000
, respectively. 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 and six months
ended
June 30, 2016
, were approximately
$15,000
and approximately
$36,000
, respectively. 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 for the
three and six months
ended
June 30, 2016
, were approximately
$27,000
and approximately
$67,000
,
respectively. We estimate that approximately
$149,000
will be paid for such benefits under the FPU Medical Plan in 2016.
The investment balances at
June 30, 2016
and
December 31, 2015
, consisted of the following:
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
June 30,
2016
|
|
December 31,
2015
|
Rabbi trust (associated with the Deferred Compensation Plan)
|
$
|
4,304
|
|
|
$
|
3,626
|
|
Investments in equity securities
|
21
|
|
|
18
|
|
Total
|
$
|
4,325
|
|
|
$
|
3,644
|
|
We classify these investments as trading securities and report them at their fair value.
For the three months ended June 30,
2016
and
2015
, we recorded a net unrealized gain of approximately
$71,000
and approximately
$4,000
, respectively, in other income in the condensed consolidated statements of income related to these investments.
For the six months ended June 30, 2016
and
2015
, we recorded an unrealized gain of approximately
$53,000
and approximately
$107,000
, 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 and six months ended
June 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
(in thousands)
|
|
|
|
|
|
|
|
|
Awards to non-employee directors
|
|
$
|
145
|
|
|
$
|
160
|
|
|
$
|
310
|
|
|
$
|
311
|
|
Awards to key employees
|
|
470
|
|
|
250
|
|
|
954
|
|
|
636
|
|
Total compensation expense
|
|
615
|
|
|
410
|
|
|
1,264
|
|
|
947
|
|
Less: tax benefit
|
|
(248
|
)
|
|
(165
|
)
|
|
(509
|
)
|
|
(381
|
)
|
Share-based compensation amounts included in net income
|
|
$
|
367
|
|
|
$
|
245
|
|
|
$
|
755
|
|
|
$
|
566
|
|
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.
A summary of the stock activity for our non-employee directors during the six months ended
June 30, 2016
is presented below:
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average
Fair Value
|
Outstanding— December 31, 2015
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
8,577
|
|
|
$
|
62.90
|
|
Vested
|
|
(8,577
|
)
|
|
$
|
62.90
|
|
Outstanding— June 30, 2016
|
|
—
|
|
|
$
|
—
|
|
At
June 30, 2016
, there was approximately
$450,000
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 six months ended
June 30, 2016
:
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average
Fair Value
|
Outstanding— December 31, 2015
|
|
110,398
|
|
|
$
|
38.34
|
|
Granted
|
|
46,571
|
|
|
$
|
67.90
|
|
Vested
|
|
(39,553
|
)
|
|
$
|
31.79
|
|
Expired
|
|
(2,325
|
)
|
|
$
|
42.25
|
|
Outstanding— June 30, 2016
|
|
115,091
|
|
|
$
|
51.85
|
|
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
June 30, 2016
, the aggregate intrinsic value of the SICP awards granted to key employees was approximately
$7.6 million
. At
June 30, 2016
, there was approximately
$3.2 million
of unrecognized compensation cost related to these awards, which is expected to be recognized from 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 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
June 30, 2016
, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Hedging Activities in 2016
In June 2016, Sharp entered into a swap agreement to mitigate the risk of fluctuations in wholesale propane index prices associated with
630,000
gallons expected to be purchased for the upcoming heating season. Under the swap agreement, Sharp will receive the difference between the index prices (Mont Belvieu prices in December 2016 through February 2017) and the swap price of
$0.5525
per gallon, to the extent the index prices exceed the swap price. If the index prices are lower than the swap price, Sharp will pay the difference. The swap agreement essentially fixes the price of the
630,000
gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreement as a cash flow
hedge, and there is no ineffective portion of this hedge. At
June 30, 2016
, the swap agreement had a fair value of approximately
$23,000
. The change in the fair value of the swap agreement is recorded as unrealized gain/loss in other comprehensive income (loss).
In January 2016, PESCO entered into a SCO supplier agreement with Columbia Gas to provide natural gas supply for Columbia Gas to service one of its local distribution customer tranches. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, which terminates on March 31, 2017.
In conjunction with the SCO supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. The contracts expire within one year. We have accounted for these contracts as fair value hedges, and any ineffective portion is reported directly in earnings. We believe these contracts are highly effective at hedging inventory. At
June 30, 2016
, PESCO had a total of
1,065,000
Dts/d hedged under natural gas futures contracts, with a liability fair value of approximately
$233,000
. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in earnings and is offset by any associated gain (loss) in the value of the inventory being hedged.
Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts expire within two years, and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At
June 30, 2016
, PESCO had a total of
6,090,000
Dts/d hedged under natural gas futures contracts, with an asset fair value of approximately
$357,000
. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).
Fair Value Hedges
The impact of our natural gas futures commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and six months ended June 30, 2016 is presented below:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
(in thousands)
|
|
|
June 30, 2016
(1)
|
|
June 30, 2016
(1)
|
Commodity contracts
|
|
$
|
(233
|
)
|
|
$
|
(233
|
)
|
Fair value adjustment for natural gas inventory designated as the hedged item
|
|
681
|
|
|
681
|
|
Total increase in purchased gas cost
|
|
$
|
448
|
|
|
$
|
448
|
|
|
|
|
|
|
|
The increase in purchased gas cost is comprised of the following:
|
|
|
|
|
Basis ineffectiveness
|
|
$
|
(83
|
)
|
|
$
|
(83
|
)
|
Timing ineffectiveness
|
|
531
|
|
|
531
|
|
Total ineffectiveness
|
|
$
|
448
|
|
|
$
|
448
|
|
|
|
(1)
|
There were no natural gas futures commodity contracts designated as fair value hedges in 2015.
|
Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedging instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that our natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.
Hedging Activities in 2015
In March, May and June 2015, Sharp paid a total of approximately
$143,000
to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with
2.5 million
gallons for the propane price cap program in the 2015-2016 heating season. We exercised the put options as propane prices fell below the strike prices of
$0.4950
,
$0.4888
and
$0.4500
per gallon in December 2015 through February 2016 and
$0.4200
per gallon in January through March 2016. We received approximately
$239,000
, which represents the difference between the market prices and the strike prices during those months. We accounted for the put options as fair value hedges.
In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with
2.5 million
gallons purchased in December 2015 through March 2016. Under these
swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from
$0.5200
to
$0.5950
per gallon, for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the
2.5 million
gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid approximately
$484,000
, which represents the difference between the index prices and swap prices during those months of the swap agreements.
Commodity Contracts for Trading Activities
Xeron engages in trading activities using forward and futures contracts for propane and crude oil. 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
June 30, 2016
, we had the following outstanding propane and crude oil trading contracts, which we accounted for as derivatives:
|
|
|
|
|
|
|
|
|
|
|
|
|
Quantity in
|
|
Estimated Market
|
|
Weighted Average
|
At June 30, 2016
|
Gallons
|
|
Prices
|
|
Contract Prices
|
Forward Contracts - Propane
|
|
|
|
|
|
Purchase
|
421,000
|
|
|
$
|
0.5375
|
|
|
$
|
0.5388
|
|
|
|
|
|
|
|
|
Quantity in
|
|
Estimated Market
|
|
Weighted Average
|
At June 30, 2016
|
Barrels
|
|
Prices
|
|
Contract Prices
|
Futures Contracts - Crude Oil
|
|
|
|
|
|
Purchase
|
20,000
|
|
|
$
|
48.3300
|
|
|
$
|
47.9000
|
|
Estimated market prices and weighted average contract prices are in dollars per gallon and barrel. All contracts expire by the end of the third 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
June 30, 2016
, Xeron had no accounts receivable or accounts payable balances to offset with these
two
counterparties. At
December 31, 2015
, Xeron had a right to offset
$431,000
of accounts payable with these
two
counterparties. At
December 31, 2015
, Xeron did not have outstanding accounts receivable with these two counterparties.
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of
June 30, 2016
and
December 31, 2015
, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
|
|
Fair Value As Of
|
(in thousands)
|
|
Balance Sheet Location
|
|
June 30, 2016
|
|
December 31, 2015
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
Forward & Future contracts
|
|
Mark-to-market energy assets
|
|
$
|
25
|
|
|
$
|
1
|
|
Derivatives designated as fair value hedges
|
|
|
|
|
|
|
Put options
|
|
Mark-to-market energy assets
|
|
—
|
|
|
152
|
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
Natural gas futures contracts
|
|
Mark-to-market energy assets
|
|
357
|
|
|
—
|
|
Propane swap agreements
|
|
Mark-to-market energy assets
|
|
23
|
|
|
—
|
|
Total asset derivatives
|
|
|
|
$
|
405
|
|
|
$
|
153
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability Derivatives
|
|
|
|
|
Fair Value As Of
|
(in thousands)
|
|
Balance Sheet Location
|
|
June 30, 2016
|
|
December 31, 2015
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
Forward contracts
|
|
Mark-to-market energy liabilities
|
|
$
|
23
|
|
|
$
|
1
|
|
Derivatives designated as fair value hedges
|
|
|
|
|
|
|
Natural gas futures contracts
|
|
Mark-to-market energy liabilities
|
|
233
|
|
|
—
|
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
Propane swap agreements
|
|
Mark-to-market energy liabilities
|
|
—
|
|
|
323
|
|
Natural gas futures contracts
|
|
Mark-to-market energy liabilities
|
|
—
|
|
|
109
|
|
Total liability derivatives
|
|
|
|
$
|
256
|
|
|
$
|
433
|
|
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 June 30,
|
|
For the Six Months Ended June 30,
|
(in thousands)
|
|
(Loss) on Derivatives
|
|
2016
|
|
2015
|
|
2016
|
|
2015
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Realized gain on forward contracts
(1)
|
|
Revenue
|
|
$
|
88
|
|
|
$
|
(71
|
)
|
|
275
|
|
|
206
|
|
Unrealized gain (loss) on forward contracts
(1)
|
|
Revenue
|
|
1
|
|
|
203
|
|
|
2
|
|
|
78
|
|
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
|
|
—
|
|
|
(30
|
)
|
|
|
|
(34
|
)
|
Natural gas futures contracts
|
|
Natural Gas Inventory
|
|
(233
|
)
|
|
—
|
|
|
(233
|
)
|
|
—
|
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
Propane swap agreements
|
|
Cost of sales
|
|
—
|
|
|
—
|
|
|
(364
|
)
|
|
—
|
|
Propane swap agreements
|
|
Other Comprehensive Gain (Loss)
|
|
23
|
|
|
10
|
|
|
23
|
|
|
(2
|
)
|
Call options
|
|
Cost of sales
|
|
—
|
|
|
—
|
|
|
—
|
|
|
(81
|
)
|
Natural gas futures contracts
|
|
Cost of sales
|
|
211
|
|
|
—
|
|
|
359
|
|
|
—
|
|
Natural gas futures contracts
|
|
Other Comprehensive Gain
|
|
786
|
|
|
—
|
|
|
472
|
|
|
—
|
|
Total
|
|
|
|
$
|
876
|
|
|
$
|
112
|
|
|
$
|
607
|
|
|
$
|
691
|
|
|
|
(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
June 30, 2016
and
December 31, 2015
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
As of June 30, 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
|
|
$
|
475
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
475
|
|
Investments—mutual funds and other
|
|
$
|
3,829
|
|
|
$
|
3,829
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mark-to-market energy assets, incl. put options and swap agreements
|
|
$
|
405
|
|
|
$
|
—
|
|
|
$
|
405
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities incl. swap agreements
|
|
$
|
256
|
|
|
$
|
—
|
|
|
$
|
256
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
As of December 31, 2015
|
|
Fair Value
|
|
Quoted- Prices- in
Active Markets
(Level 1)
|
|
Significant- Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
(in thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Investments—equity securities
|
|
$
|
18
|
|
|
$
|
18
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Investments—guaranteed income fund
|
|
$
|
279
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
279
|
|
Investments—mutual funds and other
|
|
$
|
3,347
|
|
|
$
|
3,347
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mark-to-market energy assets, incl. put/call options
|
|
$
|
153
|
|
|
$
|
—
|
|
|
$
|
153
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities, incl. swap agreements
|
|
$
|
433
|
|
|
$
|
—
|
|
|
$
|
433
|
|
|
$
|
—
|
|
The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of
June 30, 2016
and
December 31, 2015
:
Level 1 Fair Value Measurements:
Investments - equity securities
— The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Investments - mutual funds and other
— The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities —
These forward contracts are valued using market transactions in either the listed or OTC markets.
Propane put/call options, swap agreements and natural gas futures contracts –
The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.
Level 3 Fair Value Measurements:
Investments- guaranteed income fund
— The fair values of these investments are recorded at the contract value, which approximates their fair value.
The following table sets forth the summary of the changes in the fair value of Level 3 investments
for the six months ended June 30, 2016
and
2015
:
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
2016
|
|
2015
|
(in thousands)
|
|
|
|
Beginning Balance
|
$
|
279
|
|
|
$
|
287
|
|
Purchases and adjustments
|
112
|
|
|
49
|
|
Transfers
|
88
|
|
|
(3
|
)
|
Distribution
|
(8
|
)
|
|
—
|
|
Investment income
|
4
|
|
|
2
|
|
Ending Balance
|
$
|
475
|
|
|
$
|
335
|
|
Investment income from the Level 3 investments is reflected in other income (expense) in the accompanying condensed consolidated statements of income.
At
June 30, 2016
, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
Other Financial Assets and Liabilities
Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).
At
June 30, 2016
, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately
$151.8 million
. This compares to a fair value of approximately
$174.3 million
, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At
December 31, 2015
, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately
$153.7 million
, compared to the estimated fair value of approximately
$165.1 million
. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.
Our outstanding long-term debt is shown below:
|
|
|
|
|
|
|
|
|
|
|
|
June 30,
|
|
December 31,
|
(in thousands)
|
|
2016
|
|
2015
|
FPU secured first mortgage bonds
(1)
:
|
|
|
|
|
9.08% bond, due June 1, 2022
|
|
$
|
7,976
|
|
|
$
|
7,973
|
|
Uncollateralized senior notes:
|
|
|
|
|
6.64% note, due October 31, 2017
|
|
5,455
|
|
|
5,455
|
|
5.50% note, due October 12, 2020
|
|
10,000
|
|
|
10,000
|
|
5.93% note, due October 31, 2023
|
|
22,500
|
|
|
24,000
|
|
5.68% note, due June 30, 2026
|
|
29,000
|
|
|
29,000
|
|
6.43% note, due May 2, 2028
|
|
7,000
|
|
|
7,000
|
|
3.73% note, due December 16, 2028
|
|
20,000
|
|
|
20,000
|
|
3.88% note, due May 15, 2029
|
|
50,000
|
|
|
50,000
|
|
Promissory notes
|
|
168
|
|
|
238
|
|
Capital lease obligation
|
|
4,153
|
|
|
4,824
|
|
Total long-term debt
|
|
156,252
|
|
|
158,490
|
|
Less: current maturities
|
|
(12,075
|
)
|
|
(9,151
|
)
|
Less: debt issuance costs
|
|
(312
|
)
|
|
(333
|
)
|
Total long-term debt, net of current maturities
|
|
$
|
143,865
|
|
|
$
|
149,006
|
|
(1)
FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.
Shelf Agreement
On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next
three years
, up to
$150.0 million
of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed
20 years
from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase, and each request for purchase with respect to a series of Shelf Notes will specify the exact use of the proceeds.
On May 13, 2016, we formally requested that Prudential purchase
$70.0 million
of
3.25 percent
Shelf Notes under the Shelf Agreement. On May 20, 2016, Prudential formally accepted and confirmed our request. The closing of the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.
The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness or incur liens and encumbrances on any of our property or the property of our subsidiaries.
On October 8, 2015, we entered into the Credit Agreement with the Lenders for a
$150.0 million
Revolver for a term of
five years
, subject to the terms and conditions of the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures.
Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of
1.25
percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus
0.25
percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to
two years
on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to
$200.0 million
, with any increase at the sole discretion of each Lende
r. At
June 30, 2016
and December 31, 2015, we had borrowed
$40.0 million
and
$35.0 million
, respectively, under the Revolver.