N
OTES
TO
C
ONDENSED
C
ONSOLIDATED
F
INANCIAL
S
TATEMENTS
(U
NAUDITED
)
|
|
1.
|
Summary of Accounting Policies
|
Basis of Presentation
References in this document to the “Company,” “Chesapeake,” “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, 2013
. 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.
Stock Dividend
On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date of August 13, 2014 will receive one additional share of common stock for every two shares of common stock owned. The stock dividend will be issued on September 8, 2014.
FASB Statements and Other Authoritative Pronouncements
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. ASU 2014-09 is effective for reporting periods (interim and annual) beginning after December 15, 2016. We are currently assessing the impact this standard will have on our financial position and results of operations.
Recently Adopted Accounting Standards
Income Taxes (ASC 740) - In July 2013, the FASB issued ASU 2013-11,
Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists
, which requires the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of an uncertain tax position. ASU 2013-11 became effective for us on January 1, 2014. The adoption of ASU 2013-11 had no material impact on our financial position and results of operations.
|
|
2.
|
Calculation of Earnings Per Share
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands, except shares and per share data)
|
|
|
|
|
|
|
|
|
Calculation of Basic Earnings Per Share:
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
5,134
|
|
|
$
|
4,356
|
|
|
$
|
22,815
|
|
|
$
|
19,225
|
|
Weighted average shares outstanding
|
|
9,704,161
|
|
|
9,621,580
|
|
|
9,681,422
|
|
|
9,611,610
|
|
Basic Earnings Per Share
|
|
$
|
0.53
|
|
|
$
|
0.45
|
|
|
$
|
2.36
|
|
|
$
|
2.00
|
|
Calculation of Diluted Earnings Per Share:
|
|
|
|
|
|
|
|
|
Reconciliation of Numerator:
|
|
|
|
|
|
|
|
|
Net Income
|
|
$
|
5,134
|
|
|
$
|
4,356
|
|
|
$
|
22,815
|
|
|
$
|
19,225
|
|
Effect of 8.25% Convertible debentures
(1)
|
|
—
|
|
|
11
|
|
|
—
|
|
|
22
|
|
Adjusted numerator—Diluted
|
|
$
|
5,134
|
|
|
$
|
4,367
|
|
|
$
|
22,815
|
|
|
$
|
19,247
|
|
Reconciliation of Denominator:
|
|
|
|
|
|
|
|
|
Weighted shares outstanding—Basic
|
|
9,704,161
|
|
|
9,621,580
|
|
|
9,681,422
|
|
|
9,611,610
|
|
Effect of dilutive securities:
|
|
|
|
|
|
|
|
|
Share-based Compensation
|
|
33,691
|
|
|
22,454
|
|
|
34,340
|
|
|
22,789
|
|
8.25% Convertible debentures
(1)
|
|
—
|
|
|
51,436
|
|
|
—
|
|
|
52,854
|
|
Adjusted denominator—Diluted
|
|
9,737,852
|
|
|
9,695,470
|
|
|
9,715,762
|
|
|
9,687,253
|
|
Diluted Earnings Per Share
|
|
$
|
0.53
|
|
|
$
|
0.45
|
|
|
$
|
2.35
|
|
|
$
|
1.99
|
|
(1)
As of March 1, 2014, we no longer have any outstanding convertible debentures. See
Note 14, Long-term debt
for additional information.
Eastern Shore Gas Company
On May 31, 2013, the Maryland PSC approved the acquisition of ESG. Upon receiving this approval, we completed the purchase of certain operating assets of ESG, which was not related to, or affiliated with, our interstate natural gas transmission subsidiary, Eastern Shore. We paid approximately
$16.5 million
at the closing of the transaction, which was subject to certain adjustments specified in the asset purchase agreement. During the third quarter of 2013, the purchase price was reduced by
$543,000
due to adjustments to property, plant and equipment, propane inventory, accounts receivable and other accrued liabilities. The purchase price included approximately
$726,000
of sales tax related to the transaction. We financed the acquisition using unsecured short-term debt.
Approximately
11,000
residential and commercial underground propane distribution system customers and
500
bulk propane delivery customers acquired in the transaction are being served by our new subsidiary, Sandpiper, and our propane distribution subsidiary, Sharp, respectively. Sandpiper's operations, which cover all of Worcester County, Maryland, are now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution and have begun to convert some of the acquired customers. Although most of these customers are currently being served with propane, we classify Sandpiper's operations as natural gas distribution in the Regulated Energy segment.
In connection with this acquisition, we recorded
$12.6 million
in property, plant and equipment,
$384,000
in propane inventory,
$2.5 million
in accounts receivable and accrued revenue and
$227,000
in other current liabilities, which included the effect of purchase price adjustments in the third quarter of 2013 and the second quarter of 2014. All but insignificant amounts of assets and liabilities are recorded in the Regulated Energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are final, as the final purchase price allocation was completed.
The revenue from this acquisition for the three and six months ended
June 30, 2014
, included in our condensed consolidated statement of income, were
$4.2 million
and
$14.4 million
, respectively. The net income from this acquisition for the three and six months ended
June 30, 2014
, included in our condensed consolidated statement of income, were
$123,000
and
$1.8 million
, respectively.
Other Acquisitions
On December 2, 2013, we acquired certain operating assets of the City of Fort Meade, Florida, for approximately
$792,000
. The purchased assets are used to provide natural gas distribution service in the City of Fort Meade, Florida. In connection with this acquisition, we recorded
$670,000
in property, plant and equipment,
$14,000
in inventory,
$150,000
in goodwill and
$42,000
in other current liabilities. Valuation of certain property, plant and equipment is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended
June 30, 2014
were not material.
On February 5, 2013, we purchased the propane operating assets of Glades for approximately
$2.9 million
. The purchased assets are used to provide propane distribution service to approximately
3,000
residential and commercial customers in Okeechobee, Glades and Hendry Counties, Florida. In connection with this acquisition, we recorded
$1.6 million
in property, plant and equipment,
$231,000
in propane and other inventory,
$300,000
in an intangible asset related to Glades’ customer list, to be amortized over
12 years
beginning in February 2013, and
$724,000
in goodwill. All of the goodwill is expected to be deductible for income tax purposes. These amounts reflect an adjustment to the allocation of the purchase price during the first quarter of 2014 based on our final valuation, which decreased the value of propane inventory by
$271,000
and increased goodwill by the same amount. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended
June 30, 2014
were not material.
|
|
4.
|
Rates and Other Regulatory Activities
|
Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s 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
There were no rates and other regulatory activities in Delaware during the first six months of 2014.
Maryland
On March 24, 2014, Sandpiper filed a depreciation study with the Maryland PSC regarding the assets purchased in the ESG acquisition. This depreciation study was filed in accordance with the order dated May 29, 2013, which allowed Sandpiper to recommend the proper depreciation rates and accumulated depreciation associated with the acquired assets. Sandpiper recommended slightly lower depreciation rates to be applied prospectively and a reduction of
$4.5 million
in accumulated depreciation. On June 20, 2014, the Maryland PSC staff recommended lower depreciation rates than those recommended by Sandpiper and a reduction of
$5.5 million
in accumulated depreciation. The Office of People’s Counsel also recommended lower depreciation rates and no adjustment to accumulated depreciation. The parties are currently discussing a potential settlement in advance of an evidentiary hearing in August 2014.
Florida
On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU requested interim rate relief of approximately
$2.4 million
and final rate relief of approximately
$5.9 million
. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. At the July 10, 2014 Agenda Conference, the Florida PSC approved interim rate relief of approximately
$2.2 million
, as recommended by the Florida PSC staff. The interim rates are effective for meter readings on or after August 10, 2014. Any increase to our rates as a result of this interim rate relief may be subject to refund, depending on the outcome of the final rate relief request. The base rate proceeding hearing is currently scheduled for September 15-18, 2014. The revenue requirement will be determined at the Agenda Conference, currently scheduled for November 25, 2014, and final rates will be determined at the Agenda Conference, currently scheduled for December 16, 2014. Final rates are expected to be effective in January 2015.
On January 13, 2014, FPU's natural gas divisions and Chesapeake's Florida natural gas distribution division filed a consolidated natural gas depreciation study with the Florida PSC. We also filed for approval to establish a regulatory asset and related amortization to address the costs associated with the development of this study. Depending on the results of this proceeding, we may be required to change depreciation expense for our Florida natural gas distribution operations. The PSC agenda date for the depreciation study has not yet been set.
On November 15, 2013, Chesapeake's Florida natural gas distribution division petitioned the Florida PSC for an extension to its surcharge to recover an additional
$381,000
in estimated remaining environmental cleanup costs that have not yet been recovered. This extension would be effective for two years, beginning January 1, 2014. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda Conference on January 7, 2014.
Eastern Shore
The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:
TETLP Expansion Project:
On January 31, 2014, Eastern Shore submitted to the FERC a request for prior notice authorization
regarding a project
that included
certain improvements at Eastern Shore’s existing
interconnection with TETLP near Honey Brook, Pennsylvania. This project will allow Eastern Shore to
increase its capacity to receive natural gas from TETLP by
57,000
Dts/d to a total capacity of
107,000
Dts/d, but this requested improvement will not result in an increase in Eastern Shore’s overall system capacity. On April 8, 2014, the FERC approved Eastern Shore’s prior notice application, and Eastern Shore made this additional receipt point capacity available to an existing industrial customer.
White Oak Lateral Project Filing:
On June 13, 2013, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct the White Oak lateral project located in Kent County, Delaware. The project consists of installing approximately
5.5
miles of
16
-inch diameter pipeline, metering facilities and miscellaneous appurtenances, extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide
55,200
Dts/d of delivery lateral firm transportation service to an industrial customer facility currently under construction. The total cost of the project is estimated to be approximately
$11.5 million
.
On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013, with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013, and FERC staff recommended a finding of no significant impact. Eastern Shore filed the implementation plan and acceptance of conditions, stating that it will comply with all environmental conditions as set forth in the order. On November 27, 2013, the FERC issued a CP for this project. On January 17, 2014, the FERC issued its notice to allow construction to proceed, and Eastern Shore began construction activities for this project on January 22, 2014, for a planned in-service date of January 1, 2015.
Other matters:
Eastern Shore also had developments in the following FERC matters:
On May 30, 2014, Eastern Shore submitted to the FERC a combined filing of its FRP and Cash-Out Refund for a twelve-month period from April 2013 to March 2014. In this filing, Eastern Shore proposed an FRP rate of
0.62 percent
. During the period, Eastern Shore experienced an under-recovery of
$494,000
in its Deferred Gas Required for Operations costs and an over-recovery of
$160,000
in its Deferred Cash-Out costs. Eastern Shore proposed to incorporate the Cash-Out Refund into its FRP to mitigate the effect of the increase in the FRP to its customers.
|
|
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.
We have participated in the investigation and assessment of, and have remediation exposures at,
six
former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding a seventh former MGP site located in Cambridge, Maryland. We were notified in December of 2013 by the DNREC that it would be conducting a facility evaluation of an eighth former MGP site located in Seaford, Delaware.
As of
June 30, 2014
, we had approximately
$10.2 million
in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to
$14.0 million
of its environmental costs related to all of its MGP sites from insurance and from customers through rates, approximately
$9.4 million
of which has been recovered as of
June 30, 2014
. We had approximately
$4.6 million
in regulatory assets for future recovery of environmental costs from FPU’s customers.
In addition to the FPU MGP sites, we had
$454,000
in environmental liabilities at
June 30, 2014
, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of
June 30, 2014
, we had approximately
$503,000
in regulatory and other assets for future recovery through Chesapeake’s rates. 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 will be recoverable from customers through rates.
The following discussion provides details on MGP sites:
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 currently 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. It is anticipated that similar remedial actions ultimately will be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately
$4.5 million
to
$15.4 million
, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.
Sanford, Florida
FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. 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, 2014
, FPU has paid
$650,000
to the Sanford Group escrow account for its entire share of the funding requirements.
The total cost of the final remedy is now estimated to be over
$20.0 million
, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the
$650,000
committed by FPU in the Third Participation Agreement.
As of
June 30, 2014
, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be
$24,000
. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding
$13.0 million
to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the
$650,000
that FPU has paid under the Third Participation Agreement. No such claims have been made as of
June 30, 2014
.
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 new 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 4, 2012. FDEP responded via e-mail on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The most recent groundwater-monitoring event was conducted on March
13, 2014. The results were reported in a letter to FDEP dated April 26, 2014. Natural Attenuation Default Criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September of 2014.
Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated 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 FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, it is anticipated 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. Recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately
two
to
three
years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013.
An exploratory drilling program was conducted in November of 2013. The most recent groundwater monitoring event was conducted on April 11, 2014, and results were reported in a letter to FDEP dated June 6, 2014. A meeting was held with FDEP on June 12, 2014 to discuss the results of the drilling program, the groundwater conditions, and potential future remedial actions. FDEP indicated that it may be possible to close out the site with institutional controls without modifying the existing consent order. FDEP is currently evaluating its administrative options.
Even if modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed
$443,000
, which includes an estimate of
$100,000
to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, 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. We therefore 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.
Other
We are in discussions with the MDE regarding 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.
In a letter dated December 5, 2013, the DNREC notified us that it will be conducting a facility evaluation of a former MGP site in Seaford, Delaware. The facility evaluation has not been conducted, and the outcome of this evaluation cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.
|
|
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 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, which expires on March 31, 2015, with an unaffiliated energy marketing and risk management company to manage a portion of the divisions' natural gas transportation and storage capacity.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a
six
-year term. 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.
Chesapeake’s 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 is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay for the service.
In May 2014, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2015.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than
3.75
times, and (b) a fixed charge coverage ratio greater than
1.5
times. If either ratio is not met by FPU, it has
30
days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of
2
times), and (b) total debt to total capital (maximum of
65 percent
). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU having to provide an irrevocable letter of credit. As of
June 30, 2014
, FPU was in compliance with all of the requirements of its fuel supply contracts.
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. 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 against those specified in the other.
Corporate Guarantees
The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is
$45.0 million
.
We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which is for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. 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, 2014
was
$31.6 million
, with the guarantees expiring on various dates through
June 2015
.
Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see
Note 14, Long-Term Deb
t, to the condensed consolidated financial statements for further details).
In addition to the corporate guarantees, we have issued a letter of credit for
$1.0 million
, which expires on
September 12, 2014
, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for
$1.1 million
, which expires on
December 2, 2014
, as security to
satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for
$304,000
to our former primary insurance company, which will expire on
June 1, 2015
. There have been
no
draws on these letters of credit as of
June 30, 2014
. 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.
We provided a letter of credit for
$2.3 million
to TETLP related to the precedent agreement and firm transportation service agreement between our Delaware and Maryland divisions.
On July 25, 2014, we provided a letter to the Florida PSC
guaranteeing potential refunds from interim rates to be charged by our Florida electric operation. The interim rates, which provide a rate relief of approximately
$2.2 million
of revenue on an annual basis, were approved by the Florida PSC in July 2014 in connection with the base rate proceeding currently in progress. This guarantee will expire upon the release by the Florida PSC at the conclusion of the base rate proceeding. See Note 4,
Rates and Other Regulatory Activities
, for further details on the base rate proceeding involving the Florida electric operation.
Tax-related Contingencies
We are subject to various audits and reviews by the federal, state, local and other regulatory authorities regarding income taxes and taxes other than income. As of
June 30, 2014
, we maintained a liability of
$300,000
related to unrecognized income tax benefits and
$905,000
related to contingencies for taxes other than income. As of
December 31, 2013
, we maintained a liability of
$300,000
related to unrecognized income tax benefits and
$1.0 million
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 three operating segments:
|
|
•
|
Regulated Energy
. The Regulated Energy segment includes natural gas distribution, natural gas transmission operations 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. 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.
|
|
|
•
|
Other
. The “Other” segment consists primarily of our advanced information services subsidiary, as well as our unregulated subsidiaries that own real estate leased to Chesapeake and 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,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
|
|
|
|
|
Operating Revenues, Unaffiliated Customers
|
|
|
|
|
|
|
|
|
Regulated Energy
|
|
$
|
61,348
|
|
|
$
|
54,975
|
|
|
$
|
163,222
|
|
|
$
|
136,279
|
|
Unregulated Energy
|
|
34,299
|
|
|
34,273
|
|
|
114,173
|
|
|
89,264
|
|
Other
|
|
4,850
|
|
|
4,898
|
|
|
9,439
|
|
|
9,331
|
|
Total operating revenues, unaffiliated customers
|
|
$
|
100,497
|
|
|
$
|
94,146
|
|
|
$
|
286,834
|
|
|
$
|
234,874
|
|
Intersegment Revenues
(1)
|
|
|
|
|
|
|
|
|
Regulated Energy
|
|
$
|
298
|
|
|
$
|
241
|
|
|
$
|
590
|
|
|
$
|
504
|
|
Unregulated Energy
|
|
22
|
|
|
1,752
|
|
|
121
|
|
|
1,752
|
|
Other
|
|
248
|
|
|
227
|
|
|
502
|
|
|
470
|
|
Total intersegment revenues
|
|
$
|
568
|
|
|
$
|
2,220
|
|
|
$
|
1,213
|
|
|
$
|
2,726
|
|
Operating Income
|
|
|
|
|
|
|
|
|
Regulated Energy
|
|
$
|
10,711
|
|
|
$
|
8,619
|
|
|
$
|
31,802
|
|
|
$
|
25,925
|
|
Unregulated Energy
|
|
(43
|
)
|
|
447
|
|
|
10,815
|
|
|
9,816
|
|
Other and eliminations
|
|
(211
|
)
|
|
86
|
|
|
(538
|
)
|
|
(39
|
)
|
Total operating income
|
|
10,457
|
|
|
9,152
|
|
|
42,079
|
|
|
35,702
|
|
Other income, net of other expenses
|
|
405
|
|
|
24
|
|
|
413
|
|
|
312
|
|
Interest
|
|
2,303
|
|
|
2,016
|
|
|
4,459
|
|
|
4,088
|
|
Income before Income Taxes
|
|
8,559
|
|
|
7,160
|
|
|
38,033
|
|
|
31,926
|
|
Income taxes
|
|
3,425
|
|
|
2,804
|
|
|
15,218
|
|
|
12,701
|
|
Net Income
|
|
$
|
5,134
|
|
|
$
|
4,356
|
|
|
$
|
22,815
|
|
|
$
|
19,225
|
|
|
|
(1)
|
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
|
|
|
|
|
|
|
|
|
|
|
(in thousands)
|
|
June 30, 2014
|
|
December 31, 2013
|
Identifiable Assets
|
|
|
|
|
Regulated energy
|
|
$
|
716,126
|
|
|
$
|
708,950
|
|
Unregulated energy
|
|
77,800
|
|
|
100,585
|
|
Other
|
|
27,159
|
|
|
27,987
|
|
Total identifiable assets
|
|
$
|
821,085
|
|
|
$
|
837,522
|
|
Our operations are almost entirely domestic. BravePoint has infrequent transactions in foreign countries, which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.
|
|
8.
|
Accumulated Other Comprehensive Income (Loss
)
|
Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements 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 income (loss), net of related tax effects, for each component of other comprehensive income for the six months ended
June 30, 2014
and 2013.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
|
|
Commodity
|
|
|
|
|
Pension and
|
|
Contracts
|
|
|
|
|
Postretirement
|
|
Cash Flow
|
|
|
|
|
Plan Items
|
|
Hedges
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
December 31, 2013
|
|
$
|
(2,533
|
)
|
|
$
|
—
|
|
|
$
|
(2,533
|
)
|
Other comprehensive loss before reclassifications
|
|
—
|
|
|
(1
|
)
|
|
(1
|
)
|
Amounts reclassified from accumulated other comprehensive loss
|
|
61
|
|
|
—
|
|
|
61
|
|
Net current-period other comprehensive income (loss)
|
|
61
|
|
|
(1
|
)
|
|
60
|
|
June 30, 2014
|
|
$
|
(2,472
|
)
|
|
$
|
(1
|
)
|
|
$
|
(2,473
|
)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Defined Benefit
|
|
Commodity
|
|
|
|
|
Pension and
|
|
Contracts
|
|
|
|
|
Postretirement
|
|
Cash Flow
|
|
|
|
|
Plan Items
|
|
Hedges
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
December 31, 2012
|
|
$
|
(5,062
|
)
|
|
$
|
—
|
|
|
$
|
(5,062
|
)
|
Other comprehensive loss before reclassifications
|
|
(6
|
)
|
|
—
|
|
|
(6
|
)
|
Amounts reclassified from accumulated other comprehensive loss
|
|
110
|
|
|
—
|
|
|
110
|
|
Net current-period other comprehensive income
|
|
104
|
|
|
—
|
|
|
104
|
|
June 30, 2013
|
|
$
|
(4,958
|
)
|
|
$
|
—
|
|
|
$
|
(4,958
|
)
|
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended
June 30, 2014
and 2013. The only such amounts for those periods were defined benefit pension and postretirement plan items. 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,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
|
|
|
|
|
Amortization of defined benefit pension and postretirement plan items:
|
|
|
|
|
|
|
|
|
Prior service cost
(1)
|
|
$
|
15
|
|
|
$
|
15
|
|
|
$
|
30
|
|
|
$
|
30
|
|
Net loss
(1)
|
|
(67
|
)
|
|
(107
|
)
|
|
(132
|
)
|
|
(213
|
)
|
Total before income taxes
|
|
(52
|
)
|
|
(92
|
)
|
|
(102
|
)
|
|
(183
|
)
|
Income tax benefit
|
|
21
|
|
|
37
|
|
|
41
|
|
|
73
|
|
Net of tax
|
|
$
|
(31
|
)
|
|
$
|
(55
|
)
|
|
$
|
(61
|
)
|
|
$
|
(110
|
)
|
(1)
These amounts are included in the computation of net periodic costs (benefits). See
Note 9, Employee Benefit Plans
, for additional details.
Amortization of defined benefit pension and postretirement plan items is included in operations expense 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, 2014
and
2013
are set forth in the following tables:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake
Pension Plan
|
|
FPU
Pension Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
For the Three Months Ended June 30,
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
$
|
106
|
|
|
$
|
103
|
|
|
$
|
647
|
|
|
$
|
594
|
|
|
$
|
23
|
|
|
$
|
20
|
|
|
$
|
13
|
|
|
$
|
12
|
|
|
$
|
16
|
|
|
$
|
16
|
|
Expected return on plan assets
|
|
(132
|
)
|
|
(126
|
)
|
|
(772
|
)
|
|
(718
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
5
|
|
|
5
|
|
|
(20
|
)
|
|
(20
|
)
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
|
38
|
|
|
57
|
|
|
—
|
|
|
81
|
|
|
12
|
|
|
16
|
|
|
17
|
|
|
19
|
|
|
—
|
|
|
—
|
|
Net periodic cost (benefit)
|
|
12
|
|
|
34
|
|
|
(125
|
)
|
|
(43
|
)
|
|
40
|
|
|
41
|
|
|
10
|
|
|
11
|
|
|
16
|
|
|
16
|
|
Amortization of pre-merger regulatory asset
|
|
—
|
|
|
—
|
|
|
191
|
|
|
191
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
2
|
|
|
2
|
|
Total periodic cost
|
|
$
|
12
|
|
|
$
|
34
|
|
|
$
|
66
|
|
|
$
|
148
|
|
|
$
|
40
|
|
|
$
|
41
|
|
|
$
|
10
|
|
|
$
|
11
|
|
|
$
|
18
|
|
|
$
|
18
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Chesapeake
Pension Plan
|
|
FPU
Pension Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
For the Six Months Ended June 30,
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Interest cost
|
|
$
|
213
|
|
|
$
|
205
|
|
|
$
|
1,294
|
|
|
$
|
1,188
|
|
|
$
|
46
|
|
|
$
|
41
|
|
|
$
|
26
|
|
|
$
|
24
|
|
|
$
|
33
|
|
|
$
|
32
|
|
Expected return on plan assets
|
|
(265
|
)
|
|
(252
|
)
|
|
(1,545
|
)
|
|
(1,437
|
)
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Amortization of prior service cost
|
|
—
|
|
|
(1
|
)
|
|
—
|
|
|
—
|
|
|
9
|
|
|
10
|
|
|
(39
|
)
|
|
(39
|
)
|
|
—
|
|
|
—
|
|
Amortization of net loss
|
|
75
|
|
|
114
|
|
|
—
|
|
|
162
|
|
|
24
|
|
|
32
|
|
|
33
|
|
|
36
|
|
|
—
|
|
|
—
|
|
Net periodic cost (benefit)
|
|
23
|
|
|
66
|
|
|
(251
|
)
|
|
(87
|
)
|
|
79
|
|
|
83
|
|
|
20
|
|
|
21
|
|
|
33
|
|
|
32
|
|
Amortization of pre-merger regulatory asset
|
|
—
|
|
|
—
|
|
|
381
|
|
|
381
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
4
|
|
|
4
|
|
Total periodic cost
|
|
$
|
23
|
|
|
$
|
66
|
|
|
$
|
130
|
|
|
$
|
294
|
|
|
$
|
79
|
|
|
$
|
83
|
|
|
$
|
20
|
|
|
$
|
21
|
|
|
$
|
37
|
|
|
$
|
36
|
|
We expect to record pension and postretirement benefit costs of approximately
$578,000
for 2014. Included in these costs is
$769,000
related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. 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
$4.0 million
and
$4.4 million
at
June 30, 2014
and
December 31, 2013
, respectively. The amortization included in pension expense is being offset by a net periodic benefit of
$191,000
, which will reduce our total expected benefit costs to
$578,000
.
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 merger pursuant to a Florida PSC order. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income (loss). The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income (loss) that were recognized as components of net periodic benefit cost during the three and six months ended
June 30, 2014
and
2013
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2014
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
(20
|
)
|
|
$
|
—
|
|
|
(15
|
)
|
Net loss
|
|
38
|
|
|
—
|
|
|
12
|
|
|
17
|
|
|
—
|
|
|
67
|
|
Total recognized in net periodic benefit cost
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
52
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
52
|
|
Recognized from regulatory asset
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
38
|
|
|
$
|
—
|
|
|
$
|
17
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
52
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2014
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
9
|
|
|
$
|
(39
|
)
|
|
$
|
—
|
|
|
(30
|
)
|
Net loss
|
|
75
|
|
|
—
|
|
|
24
|
|
|
33
|
|
|
—
|
|
|
132
|
|
Total recognized in net periodic benefit cost
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
33
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
102
|
|
Recognized from accumulated other comprehensive loss
(1)
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
33
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
102
|
|
Recognized from regulatory asset
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
—
|
|
Total
|
|
$
|
75
|
|
|
$
|
—
|
|
|
$
|
33
|
|
|
$
|
(6
|
)
|
|
$
|
—
|
|
|
$
|
102
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Three Months Ended June 30, 2013
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
5
|
|
|
$
|
(20
|
)
|
|
$
|
—
|
|
|
(15
|
)
|
Net loss
|
|
57
|
|
|
81
|
|
|
16
|
|
|
19
|
|
|
—
|
|
|
173
|
|
Total recognized in net periodic benefit cost
|
|
$
|
57
|
|
|
$
|
81
|
|
|
$
|
21
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
158
|
|
Recognized from accumulated other comprehensive loss
|
|
$
|
57
|
|
|
$
|
15
|
|
|
$
|
21
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
92
|
|
Recognized from regulatory asset
|
|
—
|
|
|
66
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
66
|
|
Total
|
|
$
|
57
|
|
|
$
|
81
|
|
|
$
|
21
|
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
158
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
For the Six Months Ended June 30, 2013
|
|
Chesapeake
Pension
Plan
|
|
FPU
Pension
Plan
|
|
Chesapeake SERP
|
|
Chesapeake
Postretirement
Plan
|
|
FPU
Medical
Plan
|
|
Total
|
(in thousands)
|
|
|
|
|
|
|
|
|
|
|
|
|
Prior service cost (credit)
|
|
$
|
(1
|
)
|
|
$
|
—
|
|
|
$
|
10
|
|
|
$
|
(39
|
)
|
|
$
|
—
|
|
|
(30
|
)
|
Net loss
|
|
114
|
|
|
162
|
|
|
32
|
|
|
36
|
|
|
—
|
|
|
344
|
|
Total recognized in net periodic benefit cost
|
|
$
|
113
|
|
|
$
|
162
|
|
|
$
|
42
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
314
|
|
Recognized from accumulated other comprehensive loss
|
|
$
|
113
|
|
|
$
|
31
|
|
|
$
|
42
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
183
|
|
Recognized from regulatory asset
|
|
—
|
|
|
131
|
|
|
—
|
|
|
—
|
|
|
—
|
|
|
131
|
|
Total
|
|
$
|
113
|
|
|
$
|
162
|
|
|
$
|
42
|
|
|
$
|
(3
|
)
|
|
$
|
—
|
|
|
$
|
314
|
|
|
|
(1)
|
See
Note 8, Accumulated Other Comprehensive Income (Loss)
.
|
During the three and six months ended
June 30, 2014
, we contributed
$130,000
and
$221,000
, respectively, to the Chesapeake Pension Plan and
$419,000
and
$630,000
, respectively, to the FPU Pension Plan. We expect to contribute a total of
$520,000
and
$1.7 million
to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2014, which represent the minimum contribution payments required during the year.
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, 2014
, were
$22,000
and
$45,000
, respectively. We expect to pay total cash benefits of approximately
$88,000
under the Chesapeake Pension SERP in 2014. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended
June 30, 2014
, were
$22,000
and
$45,000
, respectively. We have estimated that approximately
$95,000
will be paid for such benefits under the Chesapeake Postretirement Plan in 2014. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three and six months ended
June 30, 2014
, were
$89,000
and
$144,000
, respectively. We estimate that approximately
$245,000
will be paid for such benefits under the FPU Medical Plan in 2014.
The investment balances at
June 30, 2014
and
December 31, 2013
, consist of the Rabbi Trust(s) associated with deferred compensation plan(s). We classify these investments as trading securities and report them at their fair value.
For the three months ended June 30,
2014 and 2013, we recorded a net unrealized gain of
$114,000
and a net unrealized loss of
$241,000
, respectively, in other income in the condensed consolidated statements of income related to these investments.
For the six months ended June 30, 2014
and 2013, we recorded a net unrealized gain of
$152,000
and
$42,000
, respectively, in other income in the condensed consolidated statements of income related to these investments. We also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets. This liability is adjusted each month for the gains and losses incurred by the Rabbi Trusts.
|
|
11.
|
Share-Based Compensation
|
Effective May 2, 2013, our non-employee directors and key employees are awarded 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, 2014
and 2013:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Three Months Ended
|
|
Six Months Ended
|
|
|
June 30,
|
|
June 30,
|
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
|
|
|
|
|
Awards to non-employee directors
|
|
$
|
132
|
|
|
$
|
120
|
|
|
$
|
256
|
|
|
$
|
231
|
|
Awards to key employees
|
|
295
|
|
|
341
|
|
|
809
|
|
|
630
|
|
Total compensation expense
|
|
427
|
|
|
461
|
|
|
1,065
|
|
|
861
|
|
Less: tax benefit
|
|
172
|
|
|
186
|
|
|
429
|
|
|
347
|
|
Share-Based Compensation amounts included in net income
|
|
$
|
255
|
|
|
$
|
275
|
|
|
$
|
636
|
|
|
$
|
514
|
|
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 date of the grant. 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 2014, each of our non-employee directors received an annual retainer of
806
shares of common stock under the SICP. A summary of the stock activity for our non-employee directors during the six months ended
June 30, 2014
is presented below.
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average Grant date Fair Value
|
Outstanding - December 31, 2013
|
|
—
|
|
|
$
|
—
|
|
Granted
|
|
8,866
|
|
|
$
|
62.00
|
|
Vested
|
|
8,866
|
|
|
$
|
62.00
|
|
Outstanding - June 30, 2014
|
|
—
|
|
|
$
|
—
|
|
At
June 30, 2014
, there was
$458,000
of unrecognized compensation expense related to these awards. This expense will be recognized over the period ending April 30, 2015, which approximates the expected remaining service period of those directors.
Key Employees
The table below presents the summary of the stock activity for the awards to key employees for the six months ended
June 30, 2014
:
|
|
|
|
|
|
|
|
|
|
|
Number of Shares
|
|
Weighted Average
Fair Value
|
Outstanding—December 31, 2013
|
|
80,761
|
|
|
$
|
42.30
|
|
Granted
|
|
27,628
|
|
|
$
|
59.98
|
|
Vested
|
|
26,364
|
|
|
$
|
40.30
|
|
Outstanding—June 30, 2014
|
|
82,025
|
|
|
$
|
48.90
|
|
In January and March 2014, the Board of Directors granted awards of
27,628
shares to key employees under the SICP. The awards of
23,200
shares granted in January 2014 are multi-year awards that will vest at the end of the
three
-year service period ending December 31, 2016. Another award of
4,428
shares granted in March 2014 to one key employee is a multi-year award that will vest at the end of the
three
-year service period ending December 31, 2015. 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 date each award is granted. 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, 2014
, the aggregate intrinsic value of the SICP awards awarded to key employees was
$5.9 million
.
|
|
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. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of
June 30, 2014
, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with
630,000
gallons purchased for the upcoming heating season. Under these swap agreements, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of
$1.1350
,
$1.0975
and
$1.0475
per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of those
630,000
gallons purchased for the upcoming heating season. We accounted for them as cash flow hedges, and there is no ineffective portion of these hedges. As of June 30, 2014, the swap agreements had a fair value of
$(2,000)
. The change in fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).
In May 2014, Sharp also entered into put options to protect against declines in propane prices and related potential
inventory losses associated with
630,000
gallons purchased for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of
$0.9475
,
$0.9975
and
$1.0350
per gallon, for each option agreement in December 2014 through February 2015, respectively. We will receive the difference between the market price and the strike prices during those months. We paid
$128,000
to purchase the put options. We accounted for them as fair value hedges and there is no ineffective portion of these hedges. As of
June 30, 2014
, the put options had a fair value of
$99,000
. The change in fair value of the put options effectively reduced our propane inventory balance.
In June 2013, Sharp entered into put options to protect against declines in propane prices and related potential inventory losses associated with
1.3 million
gallons purchased for the propane price cap program in the upcoming heating season. If exercised, we would have received the difference between the market price and the strike price if propane prices had fallen below the strike prices of
$0.830
per gallon in December 2013 through February of 2014, and
$0.860
per gallon in January through March 2014. We accounted for these options as fair value hedges, and there is no ineffective portion of these hedges. We paid
$120,000
to purchase the put options, which expired without exercise as the market prices exceeded the strike prices.
In May 2013, Sharp entered into a call option to protect against an increase in propane prices associated with
630,000
gallons expected to be purchased at market-based prices to supply the demands of our propane price cap program customers. The program caps the retail price that we can charge to those customers during the upcoming heating season at a pre-determined level. The call option was exercised because propane prices rose above the strike price of
$0.975
per gallon in January through March of 2014. We accounted for this call option as a derivative instrument on a mark-to-market basis with any change in its fair value being reflected in current period earnings. We paid
$72,000
to purchase the call option. In January through March of 2014, we received
$209,000
, representing the difference between the market price and the strike price during those months.
Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of
June 30, 2014
, we had the following outstanding trading contracts, which we accounted for as derivatives:
|
|
|
|
|
|
|
|
|
|
|
Quantity in
|
|
Estimated Market
|
|
Weighted Average
|
At June 30, 2014
|
Gallons
|
|
Prices
|
|
Contract Prices
|
Forward Contracts
|
|
|
|
|
|
Sale
|
630,000
|
|
|
$1.1400
|
|
$
|
1.1400
|
|
Purchase
|
631,000
|
|
|
$1.1300 - $1.3176
|
|
$
|
1.1302
|
|
Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the fourth quarter of 2014.
Xeron has 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, 2014
, Xeron had a right to offset
$1.7 million
and
$425,000
of accounts receivable and accounts payable, respectively, with these
two
counterparties. At December 31, 2013, Xeron had a right to offset
$2.8 million
and
$3.2 million
of accounts receivable and accounts payable, respectively, 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.
Fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of
June 30, 2014
and December 31, 2013, are as follows:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Asset Derivatives
|
|
|
|
|
Fair Value As Of
|
(in thousands)
|
|
Balance Sheet Location
|
|
June 30, 2014
|
|
December 31, 2013
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
Forward contracts
|
|
Mark-to-market energy assets
|
|
$
|
37
|
|
|
$
|
196
|
|
Call Option
(1)
|
|
Mark-to-market energy assets
|
|
—
|
|
|
169
|
|
Derivatives designated as fair value hedges
|
|
|
|
|
|
|
Put Options
|
|
Mark-to-market energy assets
|
|
99
|
|
|
20
|
|
Total asset derivatives
|
|
|
|
$
|
136
|
|
|
$
|
385
|
|
|
|
(1)
|
We purchased a call option for the propane price cap program in May 2013. The call option was fully exercised during 2014. There was no outstanding call option at June 30, 2014.
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Liability Derivatives
|
|
|
|
|
Fair Value As Of
|
(in thousands)
|
|
Balance Sheet Location
|
|
June 30, 2014
|
|
December 31, 2013
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
Forward contracts
|
|
Mark-to-market energy liabilities
|
|
$
|
30
|
|
|
$
|
127
|
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
Propane swap agreements
|
|
Mark-to-market energy liabilities
|
|
2
|
|
|
—
|
|
Total liability derivatives
|
|
|
|
$
|
32
|
|
|
$
|
127
|
|
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
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
Derivatives not designated as hedging instruments
|
|
|
|
|
|
|
|
|
|
|
Unrealized gain (loss) on forward contracts
|
|
Revenue
|
|
$
|
6
|
|
|
$
|
(60
|
)
|
|
(62
|
)
|
|
$
|
153
|
|
Call Option
|
|
Cost of sales
|
|
—
|
|
|
(8
|
)
|
|
137
|
|
|
(8
|
)
|
Derivatives designated as fair value hedges
|
|
|
|
|
|
|
|
|
|
|
Put/Call Options
|
|
Cost of sales
|
|
(29
|
)
|
|
—
|
|
|
(49
|
)
|
|
(28
|
)
|
Put/Call Options
|
|
Inventory
|
|
|
|
(14
|
)
|
|
|
|
(14
|
)
|
Derivatives designated as cash flow hedges
|
|
|
|
|
|
|
|
|
|
|
Propane swap agreements
|
|
Other Comprehensive loss
|
|
(2
|
)
|
|
—
|
|
|
(2
|
)
|
|
—
|
|
Total
|
|
|
|
$
|
(25
|
)
|
|
$
|
(82
|
)
|
|
$
|
24
|
|
|
$
|
103
|
|
The effects of trading activities on the condensed consolidated statements of income are the following:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Location in the
|
|
For the Three Months Ended June 30,
|
|
For the Six Months Ended June 30,
|
(in thousands)
|
|
Statements of Income
|
|
2014
|
|
2013
|
|
2014
|
|
2013
|
Realized gain on forward contracts
|
|
Revenue
|
|
$
|
84
|
|
|
$
|
110
|
|
|
$
|
1,330
|
|
|
$
|
185
|
|
Unrealized gain (loss) on forward contracts
|
|
Revenue
|
|
6
|
|
|
(60
|
)
|
|
(62
|
)
|
|
153
|
|
Total
|
|
|
|
$
|
90
|
|
|
$
|
50
|
|
|
$
|
1,268
|
|
|
$
|
338
|
|
|
|
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).
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 used at
June 30, 2014
and
December 31, 2013
:
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
June 30, 2014
|
|
Fair Value
|
|
Quoted Prices in
Active Markets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
(in thousands)
|
|
|
|
|
|
|
|
|
Assets:
|
|
|
|
|
|
|
|
|
Investments—guaranteed income fund
|
|
$
|
410
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
410
|
|
Investments—other
|
|
$
|
3,132
|
|
|
$
|
3,132
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mark-to-market energy assets, incl. put/call options
|
|
$
|
136
|
|
|
$
|
—
|
|
|
$
|
136
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities incl. swap agreements
|
|
$
|
32
|
|
|
$
|
—
|
|
|
$
|
32
|
|
|
$
|
—
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
|
Fair Value Measurements Using:
|
December 31, 2013
(in thousands)
|
|
Fair Value
|
|
Quoted Prices in
Active Markets
(Level 1)
|
|
Significant Other
Observable
Inputs
(Level 2)
|
|
Significant
Unobservable
Inputs
(Level 3)
|
Assets:
|
|
|
|
|
|
|
|
|
Investments—guaranteed income fund
|
|
$
|
458
|
|
|
$
|
—
|
|
|
$
|
—
|
|
|
$
|
458
|
|
Investments—other
|
|
$
|
2,640
|
|
|
$
|
2,640
|
|
|
$
|
—
|
|
|
$
|
—
|
|
Mark-to-market energy assets, incl. put/call options
|
|
$
|
385
|
|
|
$
|
—
|
|
|
$
|
385
|
|
|
$
|
—
|
|
Liabilities:
|
|
|
|
|
|
|
|
|
Mark-to-market energy liabilities
|
|
$
|
127
|
|
|
$
|
—
|
|
|
$
|
127
|
|
|
$
|
—
|
|
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, 2014
and 2013:
|
|
|
|
|
|
|
|
|
|
Six Months Ended
June 30,
|
|
2014
|
|
2013
|
(in thousands)
|
|
|
|
Beginning Balance
|
$
|
458
|
|
|
$
|
—
|
|
Transfers in due to change in trustee
|
—
|
|
|
425
|
|
Purchases and adjustments
|
(26
|
)
|
|
96
|
|
Transfers
|
(25
|
)
|
|
(16
|
)
|
Investment income
|
3
|
|
|
4
|
|
Ending Balance
|
$
|
410
|
|
|
$
|
509
|
|
Investment income from the Level 3 investments is reflected in other income (loss) in the accompanying condensed consolidated statements of income.
The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of
June 30, 2014
and
December 31, 2013
:
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- 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 and swap agreements—
The fair value of the propane put/call options and swap agreements are determined 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.
At
June 30, 2014
, 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, 2014
, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of
$169.7 million
. This compares to a fair value of
$188.0 million
, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At
December 31, 2013
, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of
$122.0 million
, compared to the estimated fair value of
$136.8 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)
|
|
2014
|
|
2013
|
FPU secured first mortgage bonds
(A)
:
|
|
|
|
|
9.08% bond, due June 1, 2022
|
|
$
|
7,968
|
|
|
$
|
7,967
|
|
Uncollateralized senior notes:
|
|
|
|
|
7.83% note, due January 1, 2015
|
|
2,000
|
|
|
2,000
|
|
6.64% note, due October 31, 2017
|
|
10,909
|
|
|
10,909
|
|
5.50% note, due October 12, 2020
|
|
14,000
|
|
|
14,000
|
|
5.93% note, due October 31, 2023
|
|
28,500
|
|
|
30,000
|
|
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
|
|
|
—
|
|
Convertible debentures:
|
|
|
|
|
8.25% due March 1, 2014
|
|
—
|
|
|
646
|
|
Promissory notes
|
|
344
|
|
|
445
|
|
Capital lease obligation
|
|
6,766
|
|
|
6,978
|
|
Total long-term debt
|
|
176,487
|
|
|
128,945
|
|
Less: current maturities
|
|
(11,117
|
)
|
|
(11,353
|
)
|
Total long-term debt, net of current maturities
|
|
$
|
165,370
|
|
|
$
|
117,592
|
|
|
|
(A)
|
FPU secured first mortgage bonds are guaranteed by Chesapeake.
|
Uncollateralized Senior Notes
In September 2013, we entered into the Note Agreement to issue
$70.0 million
in aggregate of Notes to the Note Holders. In December 2013, we issued the Series A Notes, with an aggregate principal amount of
$20.0 million
, at a rate of
3.73 percent
. On May 15, 2014, we issued the Series B Notes, with an aggregate principal amount of
$50.0 million
, at a rate of
3.88 percent
. The proceeds received from the issuances of the Notes were used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.
Convertible Debentures
During the first two months of 2014, Convertible Debentures totaling
$537,000
were converted to stock and
$109,000
were redeemed for cash. As of March 1, 2014, we no longer have any outstanding Convertible Debentures.