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EX-32.2 - EXHIBIT 32.2 - EV Energy Partners, LPv393313_ex32-2.htm

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION  

Washington, D.C. 20549 

 

Form 10-Q 

 

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

 

For the quarterly period ended September 30, 2014 

 

OR 

 

oTRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 

 

Commission File Number 

001-33024  

 

EV Energy Partners, L.P. 

(Exact name of registrant as specified in its charter) 

 

Delaware
(State or other jurisdiction
of incorporation or organization)
20–4745690
(I.R.S. Employer Identification No.)
   
1001 Fannin, Suite 800, Houston, Texas
(Address of principal executive offices)
77002
(Zip Code)

 

Registrant’s telephone number, including area code: (713) 651-1144 

 

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

YES þ NO o

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).

YES þ NO o

 

     Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one: 

 

Large accelerated filer þ   Accelerated filer o   Non-accelerated filer o   Smaller reporting company o

 

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).  

YES o NO þ 

 

As of November 5, 2014, the registrant had 48,572,019 common units outstanding.

 

 

 
 

 

Table of Contents   

 

PART I.  FINANCIAL INFORMATION  
   
Item 1. Condensed Consolidated Financial Statements (Unaudited) 2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 17
Item 3. Quantitative and Qualitative Disclosures About Market Risk 24
Item 4. Controls and Procedures 25
   
PART II.  OTHER INFORMATION  
   
Item 1. Legal Proceedings 25
Item 1A. Risk Factors 25
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 25
Item 3. Defaults Upon Senior Securities 26
Item 4. Mine Safety Disclosures 26
Item 5. Other Information 26
Item 6. Exhibits 26
   
Signatures 27

 

1
 

 

PART I. FINANCIAL INFORMATION 

 

ITEM 1. FINANCIAL STATEMENTS 

 

EV Energy Partners, L.P. 

Condensed Consolidated Balance Sheets 

(In thousands, except number of units) 

(Unaudited) 

 

   September 30,   December 31, 
   2014   2013 
ASSETS          
Current assets:          
Cash and cash equivalents  $11,204   $11,698 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   43,240    37,661 
Related party   5,144    2,873 
Other   339    1,111 
Derivative asset   32,422    13,543 
Other current assets   1,712    6,916 
Assets held for sale   71,934    8,012 
Total current assets   165,995    81,814 
           
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization;
September 30, 2014, $646,507; December 31, 2013, $569,770
   1,829,072    1,829,062 
Other property, net of accumulated depreciation and amortization; September 30, 2014, $878;
December 31, 2013, $754
   1,152    1,259 
Long–term derivative asset   11,876    29,088 
Investments in unconsolidated affiliates   304,087    254,978 
Other assets   6,152    8,782 
Total assets  $2,318,334   $2,204,983 
           
LIABILITIES AND OWNERS’ EQUITY          
Current liabilities:          
Accounts payable and accrued liabilities  $60,220   $46,876 
Derivative liability   110    3,348 
Liabilities related to assets held for sale   856    2,155 
Total current liabilities   61,186    52,379 
           
Asset retirement obligations   105,151    99,133 
Long–term debt   1,152,366    980,297 
Other long–term liabilities   1,032    1,241 
           
Commitments and contingencies          
           
Owners’ equity:          
Common unitholders – 48,572,019 units and 48,349,080 units issued and outstanding as of
September 30, 2014 and December 31, 2013, respectively
   1,011,671    1,083,718 
General partner interest   (13,072)   (11,785)
Total owners’ equity   998,599    1,071,933 
Total liabilities and owners’ equity  $2,318,334   $2,204,983 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

2
 

 

 EV Energy Partners, L.P. 

Condensed Consolidated Statements of Operations 

(In thousands, except per unit data) 

(Unaudited) 

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2014   2013   2014   2013 
Revenues:                    
Oil, natural gas and natural gas liquids revenues  $83,440   $80,324   $265,639   $233,325 
Transportation and marketing–related revenues   1,091    1,090    3,591    3,393 
Total revenues   84,531    81,414    269,230    236,718 
                     
Operating costs and expenses:                    
Lease operating expenses   26,579    26,185    78,002    78,496 
Cost of purchased natural gas   813    792    2,725    2,486 
Dry hole and exploration costs   3,972    1,150    5,943    2,469 
Production taxes   3,034    2,911    9,514    8,751 
Asset retirement obligations accretion expense   1,244    1,185    3,634    3,744 
Depreciation, depletion and amortization   25,723    27,936    76,961    86,439 
General and administrative expenses   9,688    8,928    34,735    30,671 
Impairment of oil and natural gas properties   946    143    2,267    8,141 
Gain on sales of oil and natural gas properties           (1,484)    
Total operating costs and expenses   71,999    69,230    212,297    221,197 
                     
Operating income   12,532    12,184    56,933    15,521 
                     
Other income (expense), net:                    
Gain (loss) on derivatives, net   37,548    (11,647)   (3,264)   (4,414)
Interest expense   (13,676)   (12,858)   (38,193)   (37,291)
Other (expense) income, net   (2)   (10)   139    232 
Total other income (expense), net   23,870    (24,515)   (41,318)   (41,473)
                    
Income (loss) before income taxes and equity in income (loss) of unconsolidated affiliates   36,402    (12,331)   15,615    (25,952)
                     
Income taxes   (157)   67    176    (326)
                    
Income (loss) before equity in income (loss) of unconsolidated affiliates   36,245    (12,264)   15,791    (26,278)
                     
Equity in income (loss) of unconsolidated affiliates   6,375    (50)   11,553    237 
                     
Net income (loss)  $42,620   $(12,314)  $27,344   $(26,041)
                     
Net income (loss) per limited partner unit:                    
Basic  $0.85   $(0.29)  $0.52   $(0.63)
Diluted  $0.85   $(0.29)  $0.52   $(0.63)
                     
Weighted average limited partner units outstanding:                    
Basic   48,572    42,599    48,561    42,578 
Diluted   48,572    42,599    48,561    42,578 
                     
Distributions declared per unit  $0.774   $0.770   $2.319   $2.307 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

3
 

 

EV Energy Partners, L.P.

Condensed Consolidated Statements of Changes in Owners’ Equity 

(In thousands, except number of units) 

(Unaudited) 

 

       General   Total 
   Common   Partner   Owners’ 
   Unitholders   Interest   Equity 
             
Balance, December 31, 2013  $1,083,718   $(11,785)  $1,071,933 
Contribution from general partner       154    154 
Distributions   (113,877)   (2,295)   (116,172)
Other   (5)       (5)
Equity–based compensation   15,038    307    15,345 
Net income   26,797    547    27,344 
Balance, September 30, 2014  $1,011,671   $(13,072)  $998,599 

 

       General   Total 
   Common   Partner   Owners’ 
   Unitholders   Interest   Equity 
             
Balance, December 31, 2012  $1,072,175   $(12,351)  $1,059,824 
Conversion of 40,264 vested phantom units   2,365        2,365 
Contributions from general partner       334    334 
Distributions   (99,643)   (2,003)   (101,646)
Equity–based compensation   12,640    258    12,898 
Net loss   (25,520)   (521)   (26,041)
Balance, September 30, 2013  $962,017   $(14,283)  $947,734 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

4
 

 

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Cash Flows 

(In thousands) 

(Unaudited) 

 

   Nine Months Ended 
   September 30, 
   2014   2013 
         
Cash flows from operating activities:          
Net income (loss)  $27,344   $(26,041)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:          
Asset retirement obligations accretion expense   3,634    3,744 
Depreciation, depletion and amortization   76,961    86,439 
Equity–based compensation cost   15,345    13,080 
Impairment of oil and natural gas properties   2,267    8,141 
Gain on sales of oil and natural gas properties   (1,484)    
Loss on derivatives, net   3,264    4,414 
Cash settlements of matured derivative contracts   (8,170)   21,748 
Equity in income of unconsolidated affiliates   (11,553)   (237)
Distributions from unconsolidated affiliates   210    171 
Other   5,634    2,313 
Changes in operating assets and liabilities:          
Accounts receivable   (7,077)   (6,430)
Other current assets   (833)   (5,435)
Accounts payable and accrued liabilities   12,360    17,889 
Other, net   (733)   (561)
Net cash flows provided by operating activities   117,169    119,235 
           
Cash flows from investing activities:          
Final settlement of purchase price of oil and natural gas properties       7,998 
Additions to oil and natural gas properties   (73,356)   (75,799)
Prepaid drilling costs   (2,501)    
Proceeds from sale of oil and natural gas properties   7,365     
Investments in unconsolidated affiliates   (105,200)   (172,003)
Distributions from unconsolidated affiliates   52    33 
Net cash flows used in investing activities   (173,640)   (239,771)
           
Cash flows from financing activities:          
Long–term debt borrowings   172,000    225,000 
Contributions from general partner   154    334 
Distributions paid   (116,172)   (101,646)
Other   (5)    
Net cash flows provided by financing activities   55,977    123,688 
           
(Decrease) increase in cash and cash equivalents   (494)   3,152 
Cash and cash equivalents – beginning of period   11,698    7,486 
Cash and cash equivalents – end of period  $11,204   $10,638 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

5
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements

 

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS 

 

Nature of Operations 

 

EV Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is a publicly held limited partnership. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates also have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights.  

 

We have two reportable segments: exploration and production and midstream. The exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. The midstream segment, which consists of our investments in Cardinal Gas Services, LLC (“Cardinal”) and Utica East Ohio Midstream LLC (“UEO”), is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio.

 

Basis of Presentation 

 

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our Annual Report on Form 10–K for the year ended December 31, 2013. 

 

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.

 

NOTE 2. EQUITY–BASED COMPENSATION  

 

We grant various forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services for us. These equity–based awards consist primarily of phantom units and performance units.  

 

We account for the phantom units issued beginning in 2009 as equity awards since we have determined that these awards will likely be settled by issuing common units. We estimated the fair value of these phantom units using the Black–Scholes option pricing model.

 

We account for the performance units as equity awards, and we estimated the fair value of these market condition performance units using the Monte Carlo simulation model.  

 

The following table presents the compensation costs recognized in our unaudited condensed consolidated statements of operations: 

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2014   2013   2014   2013 
                 
Liability awards  $   $   $   $182 
Equity awards   4,287    4,297    15,345    12,898 
Total  $4,287   $4,297   $15,345   $13,080 

 

6
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.  

 

As of September 30, 2014, there was $20.8 million of unrecognized compensation costs related to our unvested phantom units and performance units which is expected to be recognized over a weighted average period of 2.2 years.

 

NOTE 3. DIVESTITURES

 

In January 2014 and February 2014, we closed on additional sales of our Utica Shale acreage in Ohio and received aggregate proceeds of $1.5 million.

 

In January 2014, the assets and liabilities that were held for sale as of December 31, 2013 were sold for $5.8 million. In conjunction with the sale, we incurred an additional impairment charge of $0.2 million to write down these assets with a carrying amount of $6.0 million to their fair value of $5.8 million. This impairment charge was included in earnings for the nine months ended September 30, 2014. The fair value was determined using Level 2 inputs consisting of the mutually agreed upon selling price we received upon the sale of these assets.

 

NOTE 4. INVESTMENTS IN UNCONSOLIDATED AFFILIATES 

 

The most significant of our investments in unconsolidated affiliates are Cardinal and UEO. As of September 30, 2014, we own 9% of Cardinal and 21% of UEO. Cardinal and UEO are engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. In October 2014, we sold our 9% interest in Cardinal (see Note 16).

 

Summarized combined financial information for Cardinal and UEO is as follows:

 

   September 30,   December 31, 
   2014   2013 
         
Current assets  $130,575   $71,153 
Noncurrent assets   2,073,897    1,528,518 
           
Total assets  $2,204,472   $1,599,671 
           
Current liabilities  $81,823   $145,006 
Owner’s equity   2,122,649    1,454,665 
           
Total liabilities and owner’s equity  $2,204,472   $1,599,671 

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2014   2013   2014   2013 
                 
Revenues  $80,509   $18,573   $182,304   $30,801 
Operating income   46,007    2,326    83,408    7,237 
Net income   46,074    2,373    83,542    7,344 

 

As of September 30, 2014 and December 31, 2013, the excess of our investment over our equity in Cardinal and UEO is $13.9 million and $8.2 million, respectively.

 

7
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 5. RISK MANAGEMENT 

 

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. Our policies do not permit the use of derivatives for speculative purposes.  

 

We have elected not to designate any of our derivatives as hedging instruments. Accordingly, changes in the fair value of our derivatives are recorded immediately to operations as “Gain (loss) on derivatives, net” in our unaudited condensed consolidated statements of operations.  

 

As of September 30, 2014, we had entered into oil and natural gas derivatives with the following terms: 

 

Period Covered  Hedged
Volume
   Weighted
Average Fixed
Price
 
Oil (MBbls):          
Swaps – October 2014 to December 2014   377.2   $93.73 
Swaps – 2015   1,277.5    90.28 
Swaps – 2016   366.0    90.14 
           
Natural Gas (MmmBtus):          
Swaps – October 2014 to December 2014   10,009.6    4.66 
Swaps – 2015   36,317.5    4.94 
Swaps – 2016   10,980.0    4.17 

 

As of September 30, 2014, we had entered into interest rate swaps with the following terms: 

 

   Notional   Floating  Fixed 
Period Covered  Amount   Rate  Rate 
October 2014 – July 2015  $110,000   1 Month LIBOR   3.315%

 

8
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

The following table sets forth the fair values and classification of our outstanding derivatives:

 

           Net Amounts 
       Gross Amounts   of Assets 
       Offset in the   Presented in the 
   Gross   Unaudited   Unaudited 
   Amounts of   Condensed   Condensed 
   Recognized   Consolidated   Consolidated 
   Assets   Balance Sheet   Balance Sheet 
Derivatives:               
As of September 30, 2014:               
Derivative asset  $35,503   $(3,081)  $32,422 
Long–term derivative asset   11,876        11,876 
Total  $47,379   $(3,081)  $44,298 
                
As of December 31, 2013:               
Derivative asset  $24,950   $(11,407)  $13,543 
Long–term derivative asset   30,903    (1,815)   29,088 
Total  $55,853   $(13,222)  $42,631 

 

           Net Amounts 
       Gross Amounts   of Liabilities 
       Offset in the   Presented in the 
   Gross   Unaudited   Unaudited 
   Amounts of   Condensed   Condensed 
   Recognized   Consolidated   Consolidated 
   Liabilities   Balance Sheet   Balance Sheet 
Derivatives:               
As of September 30, 2014:               
Derivative liability  $3,191   $(3,081)  $110 
Long–term derivative liability            
Total  $3 191   $(3,081)  $110 
                
As of December 31, 2013:               
Derivative liability  $14,755   $(11,407)  $3,348 
Long–term derivative liability   1,815    (1,815)    
Total  $16,570   $(13,222)  $3,348 

 

We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our unaudited condensed consolidated balance sheets when such amounts are with the same counterparty. In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements. These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.

 

Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable. We could also be required to post cash collateral related to these derivatives under certain circumstances. As of September 30, 2014 and December 31, 2013, we were not required to post any collateral nor did we hold any collateral associated with our derivatives. 

 

9
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 6. FAIR VALUE MEASUREMENTS 

 

Recurring Basis 

 

The following table presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring basis: 

 

       Fair Value Measurements at the End of the 
       Reporting Period 
       Quoted         
       Prices in         
       Active         
       Markets   Significant     
       for   Other   Significant 
       Identical   Observable   Unobservable 
       Assets   Inputs   Inputs 
   Fair Value   (Level 1)   (Level 2)   (Level 3) 
As of September 30, 2014:                    
Assets – Oil and natural gas derivatives  $47,379   $   $47,379   $ 
                     
Liabilities:                    
Oil and natural gas derivatives  $618   $   $618   $ 
Interest rate swaps   2,573        2,573     
Total  $3,191   $   $ 3,191   $ 
                     
As of December 31, 2013:                    
Assets – Oil and natural derivatives  $55,853   $   $55,853   $ 
                     
Liabilities:                    
Oil and natural gas derivatives  $11,560   $   $11,560   $ 
Interest rate swaps   5,010        5,010     
Total  $16,570   $   $16,570   $ 

 

 Our derivatives consist of over–the–counter contracts which are not traded on a public exchange.  As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives using the income approach with inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves. Our estimates of fair value have been determined at discrete points in time based on relevant market data. There were no changes in valuation techniques or related inputs in the three months ended September 30, 2014. 

 

Impairment of Oil and Natural Gas Properties

 

We incurred leasehold impairment charges of $0.9 million and $0.1 million in the three months ended September 30, 2014 and 2013, respectively, and $2.1 million and $8.1 million in the nine months ended September 30, 2014 and 2013, respectively.

 

Financial Instruments 

 

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than derivatives and long–term debt approximate fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see above).  

 

10
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The estimated fair value of our senior notes due 2019 was $515.0_million and $504.7 million at September 30, 2014 and December 31, 2013, respectively, which differs from the carrying value of $499.4 million and $499.3 million at September 30, 2014 and December 31, 2013, respectively. The fair value of the senior notes due 2019 was determined using Level 2 inputs.

   

NOTE 7. ASSET RETIREMENT OBLIGATIONS 

 

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis. The changes in the aggregate ARO are as follows: 

 

   2014   2013 
Balance as of January 1  $103,173   $104,684 
Liabilities incurred   560    727 
Accretion expense   3,634    3,744 
Revisions in estimated cash flows   2,419    (6,961)
Settlements and divestitures   (2,730)   (910)
Balance as of September 30  $107,056   $101,284 

 

As of both September 30, 2014 and December 31, 2013, $1.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets. In addition, as of December 31, 2013, $2.2 million of our ARO is included in “Liabilities related to assets held for sale” in our unaudited condensed consolidated balance sheets.

 

NOTE 8. LONG–TERM DEBT 

 

Credit Facility 

 

As of September 30, 2014, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $100.0 million of available borrowing capacity for letters of credit. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense of no greater than 3.5 to 1.0. As of September 30, 2014, we were in compliance with these financial covenants. 

 

The facility does not require any repayments of amounts outstanding until it expires in April 2016. Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 3.0% and 3.1% at September 30, 2014 and 2013, respectively).  

 

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. As of September 30, 2014, the borrowing base under the facility was $730.0 million. The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

 

We had $653.0 million and $481.0 million outstanding under the facility at September 30, 2014 and December 31, 2013, respectively. 

 

11
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

8.0% Senior Notes due 2019 

 

Our senior notes due 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither EV Energy Partners, L.P. nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.  

 

The aggregate carrying amount of our senior notes due 2019 was $499.4 million and $499.3 million at September 30, 2014 and December 31, 2013, respectively.

  

NOTE 9. COMMITMENTS AND CONTINGENCIES 

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our unaudited condensed consolidated financial statements, and no amounts have been accrued at September 30, 2014 or December 31, 2013. 

 

NOTE 10. OWNERS’ EQUITY 

 

Units Outstanding 

 

At September 30, 2014, owners’ equity consists of 48,572,019 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. 

 

Issuance of Units 

 

In January 2014, we issued 0.2 million common units related to the vesting of equity–based awards. In conjunction with the vesting of these units, we received a contribution of $0.2 million by our general partner to maintain its 2% interest in us.  

 

Cash Distributions 

 

The following sets forth the distributions we paid during the nine months ended September 30, 2014:

 

Date Paid  Period Covered  Distribution
per Unit
   Total
Distribution
 
February 14, 2014  October 1, 2013 – December 31, 2013  $0.771   $38,696 
May 15, 2014  January 1, 2014 – March 31, 2014   0.772    38,716 
August 14, 2014  April 1, 2014 – June 30, 2014   0.773    38,760 
           $116,172 

 

On October 27, 2014, the board of directors of EV Management declared a $0.774 per unit distribution for the third quarter of 2014 on all common units. The distribution of $38.8 million is to be paid on November 14, 2014 to unitholders of record at the close of business on November 7, 2014.

 

12
 

  

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 11. NET INCOME (LOSS) PER LIMITED PARTNER UNIT 

 

The following sets forth the calculation of net income (loss) per limited partner unit: 

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2014   2013   2014   2013 
Net income (loss)  $42,620   $(12,314)  $27,344   $(26,041)
General partner’s 2% interest in net income (loss)   (852)   246    (547)   521 
Net income (loss) attributable to unvested phantom units   (492)   (497)   (1,385)   (1,498)
Limited partners’ interest in net income (loss)  $41,276   $(12,565)  $25,412   $(27,018)
                     
Weighted average limited partner units outstanding:                    
Denominator for basic net loss per limited partner unit – common units   48,572    42,599    48,561    42,578 
Dilutive units (1)                
Total   48,572    42,599    48,561    42,578 
                     
Net income (loss) per limited partner unit:                    
Basic  $0.85   $(0.29)  $0.52   $(0.63)
Diluted  $0.85   $(0.29)  $0.52   $(0.63)

 

_____________ 

(1)Unearned performance units totaling 0.2 million units were not included in the computation of diluted net income (loss) per limited partner unit because the effect would have been anti–dilutive.

 

NOTE 12. RELATED PARTY TRANSACTIONS 

 

Pursuant to an omnibus agreement, we paid EnerVest $3.1 million and $2.5 million in the three months ended September 30, 2014 and 2013, respectively, and $9.1 million and $7.5 million in the nine months ended September 30, 2014 and 2013, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.  

 

We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest approximately $3.9 million and $4.2 million in the three months ended September 30, 2014 and 2013, respectively, and $12.2 million and $12.0 million in the nine months ended September 30, 2014 and 2013, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis. These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

 

In 2011, we and certain institutional partnerships managed by EnerVest carved out 7.5% overriding royalty interests ("ORRI") from certain acres in Ohio (the "Underlying Properties"), which we believe may be prospective for the Utica Shale, and contributed the ORRI to a newly formed limited partnership.  EnerVest is the general partner of this partnership.  The ORRI entitles the partnership to an average approximate 5.64% of the gross revenues from the Underlying Properties.  We own a 48% limited partner interest in the partnership and account for our investment using the equity method of accounting. We recognized income from unconsolidated affiliates of $0.1 million and $0.1 million in the three months ended September 30, 2014 and 2013, respectively, and $0.3 million and $0.2 million in the nine months ended September 30, 2014 and 2013, respectively. In addition, we received distributions of $0.1 million and $0.1 million in the three months ended September 30, 2014 and 2013, respectively, and $0.2 million and $0.1 million in the nine months ended September 30, 2014 and 2013, respectively.

 

13
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 13. OTHER SUPPLEMENTAL INFORMATION  

 

Supplemental cash flows and noncash transactions were as follows: 

 

   Nine Months Ended 
   September 30, 
   2014   2013 
         
Supplemental cash flows information – cash paid for interest, net of capitalized interest of $5,741 and $4,970 at September 30, 2014 and 2013, respectively  $25,783   $24,347 
           
Cash paid for income taxes  $155   $325 

 

   As of September 30, 
   2014   2013 
Noncash transaction – costs for additions to oil and natural gas properties in accounts payable and accrued liabilities  $20,973   $16,636 

 

Accounts payable and accrued liabilities consisted of the following:

 

   September 30,   December 31, 
   2014   2013 
Costs for additions to oil and natural gas properties  $20,137   $19,450 
Lease operating expenses   9,100    7,793 
Interest   18,759    8,701 
Production and ad valorem taxes   6,344    4,862 
General and administrative expenses   2,549    2,082 
Current portion of ARO   1,885    1,885 
Derivative settlements   341    1,443 
Other   1,105    660 
Total  $60,220   $46,876 

 

NOTE 14. SEGMENT INFORMATION

 

We have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. Our midstream segment, which consists of Cardinal and UEO, is accounted for using the equity method of accounting and is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. All of our operations are located in the United States.

 

Management evaluates the performance of our segments based on segment profits, which include segment revenues and direct segment costs and expenses. Segment profit excludes items such as asset retirement obligations accretion expense, depreciation, depletion and amortization, general and administrative expenses, impairment of oil and natural gas properties, gain (loss) on derivatives, interest expense and other income (expense).

 

14
 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Summarized financial information for our reporting segments is shown below:

 

   Exploration
and
Production
   Midstream   Consolidated
Total
 
             
Three months ended September 30, 2014:               
Total revenues  $84,531   $   $84,531 
Segment profit   50,133        50,133 
Equity in income of unconsolidated affiliates   78    6,297    6,375 
                
Three months ended September 30, 2013:               
Total revenues   81,414        81,414 
Segment profit   50,376        50,376 
Equity in income (loss) of unconsolidated affiliates   99    (149)   (50)
                
Nine months ended September 30, 2014:               
Total revenues   269,230        269,230 
Segment profit   173,046        173,046 
Equity in income of unconsolidated affiliates   316    11,237    11,553 
                
Nine months ended September 30, 2013:               
Total revenues   236,718        236,718 
Segment profit   144,516        144,516 
Equity in income of unconsolidated affiliates   205    32    237 
                
As of September 30, 2014:               
Total assets   1,947,214    371,120    2,318,334 
                
As of December 31, 2013:               
Total assets   1,950,300    254,683    2,204,983 

 

The following table reconciles the segment profits reported above to income (loss) before income taxes and equity in income (loss) of unconsolidated affiliates:

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2014   2013   2014   2013 
Segment profit  $50,133   $50,376   $173,046   $144,516 
Asset retirement obligations accretion expense   (1,244)   (1,185)   (3,634)   (3,744)
Depreciation, depletion and amortization   (25,723)   (27,936)   (76,961)   (86,439)
General and administrative expenses   (9,688)   (8,928)   (34,735)   (30,671)
Impairment of oil and natural gas properties   (946)   (143)   (2,267)   (8,141)
Gain on sales of oil and natural gas properties outstanding:           1,484     
Gain (loss) on derivatives, net   37,548    (11,647)   (3,264)   (4,414)
Interest expense   (13,676)   (12,858)   (38,193)   (37,291)
Other income (expense)   (2)   (10)   139    232 
Income (loss) before income taxes and equity in income (loss) of unconsolidated affiliates  $36,402   $(12,331)  $15,615   $(25,952)

 

NOTE 15. NEW ACCOUNTING STANDARDS  

 

In April 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. This ASU amends the definition of a discontinued operation and requires entities to provide additional disclosures about disposal transactions that do not meet the discontinued operations criteria. This ASU requires discontinued operations treatment for disposals of a component or group of components that represent a strategic shift that has or will have a major impact on an entity’s operations or financial results. The provisions of ASU 2014–08 are applicable to annual reporting periods beginning after December 15, 2014 and interim periods within those annual periods. Early adoption is permitted for any annual or interim period for which an entity’s financial statements have not yet been previously issued or made available for issuance. We have chosen to adopt ASU 2014–08 as of September 30, 2014. There was no material impact on our unaudited condensed consolidated financial statements.

 

15
 

 

 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

In May 2014, the FASB issued ASU No. 2014–09, Revenue from Contracts with Customers. This ASU will supersede virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We have not yet determined the effect that adopting this ASU will have on our unaudited condensed consolidated financial statements.

 

In August 2014, the FASB issued AU No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

 

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2014 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

  

NOTE 16. SUBSEQUENT EVENTS

 

In October 2014, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $30.6 million. We will retain all non–Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments. As of September 30, 2014, we have $4.6 million of oil and natural gas properties classified as assets held for sale and $0.9 million of accounts payable and accrued liabilities classified as liabilities related to assets held for sale in our unaudited condensed consolidated balance sheets. Operating results related to the Eagle Ford formation were included in our exploration and production segment.

 

In October 2014, we closed on the sale of our nine percent interest in Cardinal for $161.1 million, which included certain purchase price adjustments and transaction-related expenses. The transaction is subject to additional customary purchase price adjustments. As of September 30, 2014, we have $67.4 million of investments in unconsolidated affiliates classified as assets held for sale in our unaudited condensed consolidated balance sheets. We recognized equity in income of unconsolidated affiliates related to our interest in Cardinal of $2.5 million and $0.5 million in the three months ended September 30, 2014 and 2013, respectively, and $4.7 million and $1.2 million in the nine months ended September 30, 2014 and 2013, respectively, and these amounts were reported in our midstream segment.

 

In November 2014, the borrowing base under the facility was reaffirmed at $730.0 million.

 

We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated financial statements were issued.

 

16
 

 

ITEM 2. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS  

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2013. 

 

OVERVIEW  

 

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company. 

 

We have two reportable segments: exploration and production and midstream. Our exploration and production segment is responsible for the acquisition, development and production of our oil and natural gas properties. As of September 30, 2014, our midstream segment, which consists of our investments in Cardinal and UEO, is engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. We account for our investments in Cardinal and UEO using the equity method of accounting. In October 2014, we sold our 9% interest in Cardinal.

 

Our oil and natural gas properties are located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, Central and East Texas (which includes the Austin Chalk area), the San Juan Basin, Michigan, and the Permian Basin. As of December 31, 2013, we had estimated net proved reserves of 13.1 MMBbls of oil, 819.7 Bcf of natural gas and 48.9 MMBbls of natural gas liquids, or 1,191.6 Bcfe, and a standardized measure of $1,039.8 million.

 

CURRENT DEVELOPMENTS 

 

In January 2014 and February 2014, we closed on additional sales of our Utica Shale acreage in Ohio and received aggregate proceeds of $1.5 million.

 

In January 2014, the assets and liabilities that were held for sale as of December 31, 2013 were sold for $5.8 million.

 

In the nine months ended September 30, 2014, we invested $105.2 million in our midstream segment.

 

In October 2014, we, along with certain institutional partnerships managed by EnerVest, closed on the sale of certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties, Texas, and our share of the proceeds was $30.6 million. We will retain all non–Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is subject to customary purchase price adjustments.

 

In October 2014, we closed on the sale of our 9% interest in Cardinal for $161.1 million, which included certain purchase price adjustments and transaction-related expenses . The transaction is subject to additional customary purchase price adjustments.

 

BUSINESS ENVIRONMENT

 

Our primary business objective is to provide stability and growth in cash distributions per unit over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

 

·the prices at which we will sell our oil, natural gas liquids and natural gas production;

 

·our ability to hedge commodity prices;

 

·the distributions that we may receive from our interest in UEO;

 

·the amount of oil, natural gas liquids and natural gas we produce; and

 

·the level of our operating and administrative costs.

 

17
 

 

Oil, natural gas and natural gas liquids prices are expected to be volatile in the future. Factors affecting the price of oil include worldwide economic conditions, geopolitical activities, worldwide supply disruptions, weather conditions, actions taken by the Organization of Petroleum Exporting Countries and the value of the U.S. dollar in international currency markets. Factors affecting the price of natural gas and natural gas liquids include the discovery of substantial accumulations of natural gas in unconventional reservoirs due to technological advancements necessary to commercially produce these unconventional reserves, North American weather conditions, industrial and consumer demand for natural gas and natural gas liquids, storage levels of natural gas and natural gas liquids and the availability and accessibility of natural gas deposits in North America.

 

In order to mitigate the impact of changes in prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. By removing a significant portion of this price volatility on our future production, we have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. If commodity prices are depressed for an extended period of time, it could alter our acquisition and development plans, and adversely affect our growth strategy and ability to access additional capital in the capital markets.

 

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

 

We focus our efforts on increasing our reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

 

UEO generates revenues from fees charged for gathering, compressing, processing, fractionating and storing natural gas and natural gas liquids. The primary drivers of revenues are the capacity of our midstream facilities and the production available for gathering, processing and fractionating. As we account for our investment in UEO using the equity method of accounting, our proportionate share of its revenues or expenses is reflected in “Equity in income (loss) of unconsolidated affiliates” in our unaudited condensed consolidated statements of operations.

 

Utica Shale

 

Primarily through acquisitions completed in 2009 and 2010, we hold over 170,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average ORRI in 880,000 gross acres in Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. At September 30, 2014, our estimated net proved reserves in the Utica Shale were not material to us. Exploration and development activities targeting the Utica Shale are progressing, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area.

 

The Utica Shale area can be divided into wet natural gas, volatile oil, black oil and dry natural gas areas. Most drilling activity in the Utica Shale area has been in the wet natural gas area, but drilling activity is increasing in the dry natural gas and volatile oil areas. The current focus in the volatile oil area is on hydraulic fracturing techniques necessary to economically drill and produce in this area.

 

In mid–2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale, and in 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica Shale acreage. Through September 2014, we have closed on sales with proceeds of $45.6 million for these acres. We continue to pursue additional forms of monetizations, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.

 

18
 

 

RESULTS OF OPERATIONS 

 

   Three Months Ended
September 30,
   Nine Months Ended
September 30,
 
   2014   2013   2014   2013 
Production data:                    
Oil (MBbls)   270    279    790    787 
Natural gas liquids (MBbls)   593    538    1,714    1,567 
Natural gas (MMcf)   11,000    10,555    32,798    31,879 
Net production (MMcfe)   16,172    15,453    47,817    46,000 
Average sales price per unit:                    
Oil (Bbl)  $93.73   $102.15   $95.54   $96.26 
Natural gas liquids (Bbl)   29.30    30.72    31.00    29.98 
Natural gas (Mcf)   3.71    3.35    4.18    3.47 
Mcfe   5.16    5.20    5.56    5.07 
Average unit cost per Mcfe:                    
Production costs:                    
Lease operating expenses  $1.64   $1.69   $1.63   $1.71 
Production taxes   0.19    0.19    0.20    0.19 
Total   1.83    1.88    1.83    1.90 
Depreciation, depletion and amortization   1.59    1.81    1.61    1.88 
General and administrative expenses   0.60    0.58    0.73    0.67 

 

Three Months Ended September 30, 2014 Compared with the Three Months Ended September 30, 2013

 

Net income (loss) for the three months ended September 30, 2014 was $42.6 million compared with $(12.3) million for the three months ended September 30, 2013. The significant factors in this change were (i) a $49.2 million favorable change in gain (loss) on derivatives, net; (ii) a $6.4 million increase in equity in income (loss) of unconsolidated affiliates; (iii) a $3.1 million increase in total revenues; and (iv) a $2.2 million decrease in depreciation, depletion and amortization (“DD&A”); partially offset by a $2.8 million increase in dry hole and exploration expenses.

 

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2014 totaled $83.4 million, an increase of $3.1 million compared with the three months ended September 30, 2013. This was the result of increases of $3.8 million related to higher prices for natural gas and $3.2 million related to increased natural gas and natural gas liquids production offset by $3.1 million of lower oil and natural gas liquids prices and $0.8 million of decreased oil production. 

 

Lease operating expenses for the three months ended September 30, 2014 increased $0.4 million compared with the three months ended September 30, 2013 as the result of $1.2 million related to our expanded development drilling program offset by $0.8 million from a lower unit cost per Mcfe. Lease operating expenses per Mcfe were $1.64 in the three months ended September 30, 2014 compared with $1.69 in the three months ended September 30, 2013.  

 

Dry hole and exploration costs for the three months ended September 30, 2014 increased $2.8 million compared with the three months ended September 30, 2013 as a result of higher costs in the Appalachian Basin.

 

DD&A for the three months ended September 30, 2014 decreased $2.2 million compared with the three months ended September 30, 2013 due to $3.3 million from a lower average DD&A rate per Mcfe offset by $1.1 million from increased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2013. Depreciation, depletion and amortization for the three months ended September 30, 2014 was $1.59 per Mcfe compared with $1.81 per Mcfe for the three months ended September 30, 2013.  

 

General and administrative expenses for the three months ended September 30, 2014 totaled $9.7 million, an increase of $0.8 million compared with the three months ended September 30, 2013. This increase is primarily the result of $0.5 million of higher fees paid to EnerVest under the omnibus agreement and $0.3 million of additional separation payments made to a former officer. General and administrative expenses were $0.60 per Mcfe in the three months ended September 30, 2014 compared with $0.58 per Mcfe in the three months ended September 30, 2013.

 

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In the three months ended September 30, 2014, we incurred leasehold impairment charges of $0.9 million in the Mid–Continent area. In the three months ended September 30, 2013, we incurred leasehold impairment charges of $0.1 million.

 

Gain (loss) on derivatives, net was $37.5 million for the three months ended September 30, 2014 compared with $(11.6) million for the three months ended September 30, 2013. This change was attributable to changes in future oil and natural gas prices and the impact of decreased cash settlements of matured derivative contracts with more favorable terms that expired as of December 31, 2013. The 12 month forward price at September 30, 2014 for oil averaged $87.16 per Bbl compared with $97.49 per Bbl at June 30, 2014, and the 12 month forward price at September 30, 2014 for natural gas averaged $3.92 per MmBtu compared with $4.07 at June 30, 2014. The 12 month forward price at September 30, 2013 for oil averaged $106.24 per Bbl compared with $93.33 at June 30, 2013, and the 12 month forward prices at September 30, 2013 for natural gas averaged $3.57 per MmBtu compared with $3.74 at June 30, 2013.

 

Interest expense for the three months ended September 30, 2014 increased $0.8 million compared with the three months ended September 30, 2013 due to a decrease of $0.4 million in capitalized interest and $1.0 million from a higher weighted average long–term debt balance offset by $0.6 million from a lower weighted effective interest rate offset.

 

Equity in income (loss) of unconsolidated affiliates was $6.4 million for the three months ended September 30, 2014 compared with $(0.05) million for the three months ended September 30, 2013. The significant factor in the increase was the commencement of operations at both Cardinal and UEO, with throughput continuing to increase as more wells come on line.

 

Nine Months Ended September 30, 2014 Compared with the Nine Months Ended September 30, 2013

 

Net income (loss) for the nine months ended September 30, 2014 was $27.3 million compared with $(26.0) million for the nine months ended September 30, 2013. The significant factors in this change were (i) a $32.5 million increase in total revenues; (ii) an $11.3 million of higher equity in income (loss) of unconsolidated affiliates; (iii) a $9.5 million decrease in DD&A; and (iv) a $5.9 million decrease in impairments of our oil and natural gas properties; partially offset by (v) a $4.1 million increase in general and administrative expenses and (vi) $3.5 million of higher dry hole and exploration costs.

 

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2014 totaled $265.6 million, an increase of $32.3 million compared with the nine months ended September 30, 2013. This was the result of increases of $24.2 million related to higher prices for natural gas and natural gas liquids and $8.7 million related to increased production offset by $0.6 million from lower prices for oil. 

 

Lease operating expenses for the nine months ended September 30, 2014 decreased $0.5 million compared with the nine months ended September 30, 2013 as the result of $3.5 million from a lower unit cost per Mcfe, primarily related to decreased gathering costs at our Barnett Shale oil and natural gas properties offset by $3.0 million from our expanded development drilling program. Lease operating expenses per Mcfe were $1.63 in the nine months ended September 30, 2014 compared with $1.71 in the nine months ended September 30, 2013.  

 

Dry hole and exploration costs for the nine months ended September 30, 2014 increased $3.5 million compared with the nine months ended September 30, 2013 as a result of higher costs in the Appalachian Basin.

 

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the nine months ended September 30, 2014 increased $0.8 million compared with the nine months ended September 30, 2013 primarily due to increased oil, natural gas and natural gas liquids revenues. Production taxes for the nine months ended September 30, 2014 were $0.20 per Mcfe compared with $0.19 per Mcfe for the nine months ended September 30, 2013.  

 

DD&A for the nine months ended September 30, 2014 decreased $9.5 million compared with the nine months ended September 30, 2013 due to $12.4 million from a lower average DD&A rate per Mcfe offset by $2.9 million from increased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2013. Depreciation, depletion and amortization for the nine months ended September 30, 2014 was $1.61 per Mcfe compared with $1.88 per Mcfe for the nine months ended September 30, 2013.  

 

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General and administrative expenses for the nine months ended September 30, 2014 totaled $34.7 million, an increase of $4.1 million compared with the nine months ended September 30, 2013. This increase is primarily the result of (i) $2.3 million of additional equity compensation costs related to the accelerated vesting of the phantom units of a former officer; (ii) $1.6 million of higher fees paid to EnerVest under the omnibus agreement; and (iii) $1.0 million of higher compensation costs due to the separation payment made to a former officer partially offset by $1.0 million of lower compensation costs primarily related to the January 2014 vesting of our phantom units issued under our equity–based compensation plan. General and administrative expenses were $0.73 per Mcfe in the nine months ended September 30, 2014 compared with $0.67 per Mcfe in the nine months ended September 30, 2013.  

 

In the nine months ended September 30, 2014, we incurred impairment charges of $2.3 million, of which $0.2 million related to a charge to write down assets held for sale to their fair value and $2.1 million related to leasehold impairment charges primarily in the Mid–Continent area. In the nine months ended September 30, 2013, we incurred leasehold impairment charges of $8.1 million.

 

Gain (loss) on derivatives, net was $(3.3) million for the nine months ended September 30, 2014 compared with $(4.4) million for the nine months ended September 30, 2013. This change was attributable to changes in future oil and natural gas prices and the impact of decreased cash settlements of matured derivative contracts with more favorable terms that expired as of December 31, 2013. The 12 month forward price at September 30, 2014 for oil averaged $87.16 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at September 30, 2014 for natural gas averaged $3.92 per MmBtu compared with $4.19 at December 31, 2013. The 12 month forward price at September 30, 2013 for oil averaged $106.24 per Bbl compared with $93.09 at December 31, 2012, and the 12 month forward prices at September 30, 2013 for natural gas averaged $3.57 per MmBtu compared with $3.54 at December 31, 2012.

 

Interest expense for the nine months ended September 30, 2014 increased $0.9 million compared with the nine months ended September 30, 2013 due to $3.8 million from a higher weighted average long–term debt balance and a $0.8 million decrease in capitalized interest offset by $2.1 million from a lower weighted average effective interest rate.

 

Equity in income of unconsolidated affiliates was $11.6 million for the nine months ended September 30, 2014 compared with $0.2 million for the nine months ended September 30, 2013. The significant factor in the increase was the commencement of operations at both Cardinal and UEO, with throughput continuing to increase as more wells come on line.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, contributions to our midstream investments, distributions to our unitholders and general partner and working capital needs. For 2014, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget, pay distributions to our unitholders and general partner and satisfy our short–term liquidity needs. We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

 

Long–term Debt

 

As of September 30, 2014, we have a $1.0 billion credit facility that expires in April 2016. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of September 30, 2014, the borrowing base was $730.0 million, and we had $653.0 million outstanding. In November 2014, the borrowing base under the facility was reaffirmed at $730.0 million.

 

As of September 30, 2014, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019. As of September 30, 2014, the aggregate carrying amount of the senior notes due 2019 was $499.4 million.

 

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For additional information about our long–term debt, such as interest rates and covenants, please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein.

 

Cash and Short–term Investments

 

At September 30, 2014, we had $11.2 million of cash and short–term investments, which included $5.2 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with major financial institutions.  

 

Counterparty Exposure

 

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility.  Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of September 30, 2014, all of our counterparties have performed pursuant to their derivative contracts.

 

Cash Flows

 

Cash flows provided by (used in) type of activity were as follows:

 

   Nine Months Ended
September 30,
 
   2014   2013 
Operating activities  $117,169   $119,235 
Investing activities   (173,640)   (239,771)
Financing activities   55,977    123,688 

 

Operating Activities

 

Cash flows from operating activities provided $117.2 million and $119.2 million in the nine months ended September 30, 2014 and 2013, respectively. The significant factors in the change were a $32.5 million increase in our oil, natural gas and natural gas liquids revenues offset by $29.9 million of decreased cash settlements from our matured derivative contracts and an increase in working capital, primarily related to higher accounts receivable from our higher oil, natural gas and natural gas liquids revenues. The decreased cash settlements are due to increased oil, natural gas and natural gas liquids prices and the impact of derivative contracts with more favorable terms that expired as of December 31, 2013.

 

Investing Activities

 

During the nine months ended September 30, 2014, we spent $73.4 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $105.2 million. In addition, we received $7.4 million in proceeds from the sale of oil and natural gas properties.

 

During the nine months ended September 30, 2013, we spent $75.8 million for additions to our oil and natural gas properties and increased our investment in unconsolidated affiliates by $172.0 million. In addition, we received $8.0 million in final purchase price settlements related to our August 2012 acquisition of additional working interests in acreage in Ohio.

 

Financing Activities

 

During the nine months ended September 30, 2014, we received $172.0 million from borrowings under our credit facility and paid distributions of $116.2 million to holders of our common units, phantom units and our general partner.

 

During the nine months ended September 30, 2013, we received $225.0 million from borrowings under our credit facility and paid distributions of $101.6 million to holders of our common units, phantom units and our general partner.

 

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FORWARD–LOOKING STATEMENTS

 

This Form 10–Q contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements relate to, among other things, the following:

 

·our future financial and operating performance and results;

 

·our business strategy and plans, including plans for the sale of acreage in the Utica Shale;

 

·our estimated net proved reserves, PV–10 value and standardized measure;

 

·market prices;

 

·our future derivative activities; and

 

·our plans and forecasts.

 

We have based these forward–looking statements on our current assumptions, expectations and projections about future events.

 

 The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information. We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–Q including, but not limited to:

 

·fluctuations in prices of oil, natural gas and natural gas liquids;

 

·significant disruptions in the financial markets;

 

·future capital requirements and availability of financing;

 

·our limited control over operations in our midstream business;

 

·uncertainty inherent in estimating our reserves;

 

·risks associated with drilling and operating wells;

 

·discovery, acquisition, development and replacement of reserves;

 

·cash flows and liquidity;

 

·timing and amount of future production of oil, natural gas and natural gas liquids;

 

·availability of drilling and production equipment;

 

·marketing of oil, natural gas and natural gas liquids;

 

·developments in oil and natural gas producing countries;

 

·competition;

 

·general economic conditions;

 

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·governmental regulations;

 

·activities taken or non–performance by third parties, including suppliers, contractors, operators, transporters and purchasers of our production and counterparties to our derivative financial instruments;

 

·hedging decisions, including whether or not to enter into derivative financial instruments;

 

·actions of third party co–owners of interest in properties in which we also own an interest;

 

·fluctuations in interest rates and the value of the U.S. dollar in international currency markets; and

 

·our ability to effectively integrate companies and properties that we acquire.

 

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2013.

 

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil, natural gas and natural gas liquids. Declines in prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower prices also may reduce the amount of oil, natural gas or natural gas liquids that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and estimated quantities of our reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivative instruments to manage or reduce market risk, but do not enter into derivative agreements for speculative purposes.

 

We do not designate these or plan to designate future derivative instruments as hedges for accounting purposes. Accordingly, the changes in the fair value of these instruments are recognized currently in earnings.

 

Commodity Price Risk

 

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, derivatives to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre–existing or anticipated sales of oil, natural gas and natural gas liquids.

 

We have entered into derivatives to hedge a portion of our anticipated oil and natural gas production through December 2016. As of September 30, 2014, we have derivatives covering approximately 50% of our production attributable to our estimated net proved reserves from October 2014 through December 2016, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our derivatives at September 30, 2014 was a net asset of $46.8 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas derivatives of approximately $40.6 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

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Interest Rate Risk

 

Our floating rate credit facility and interest rate swaps also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for the nine months ended September 30, 2014 would have increased by approximately $4.5 million. The fair value of our interest rate swaps at September 30, 2014 was a liability of $2.6 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $0.8 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

ITEM 4. CONTROLS AND PROCEDURES

 

On May 14, 2013, the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”) issued an updated version of its Internal Control – Integrated Framework (the “2013 Framework”). Originally issued in 1992 (the “1992 Framework”), the framework helps organizations design, implement and evaluate the effectiveness of internal control concepts and simplify their use and application. The 1992 Framework remains available during the transition period, which extends to December 15, 2014, after which time COSO will consider it as superseded by the 2013 Framework. As of September 30, 2014, we continue to utilize the 1992 Framework during the transition to the 2013 Framework by the end of 2014.

 

Evaluation of Disclosure Controls and Procedures

 

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2014 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

 

Change in Internal Controls Over Financial Reporting

 

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended September 30, 2014 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

 

PART II. OTHER INFORMATION

 

ITEM 1. LEGAL PROCEEDINGS

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material adverse effect on our unaudited condensed consolidated financial statements.

 

ITEM 1A. RISK FACTORS

 

There have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2013.

 

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

 

None.

 

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ITEM 3. DEFAULTS UPON SENIOR SECURITIES

 

None.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable.

 

ITEM 5. OTHER INFORMATION

 

None.

 

ITEM 6. EXHIBITS 

 

The exhibits listed below are filed or furnished as part of this report: 

 

3.1First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.2First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.3Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.4First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 18, 2008).

 

4.1Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

 

10.1Sixth Amendment dated September 19, 2014 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on September 25, 2014).

 

+31.1Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer. 

 

+31.2Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer. 

 

+32.1Section 1350 Certification of Chief Executive Officer.  

 

+32.2Section 1350 Certification of Chief Financial Officer. 

 

+101Interactive Data Files. 

 

 

+Filed herewith 

 

26
 

 

SIGNATURES 

 

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.  

 

  EV Energy Partners, L.P. 
  (Registrant) 
     
Date:  November 10, 2014 By: /s/ MICHAEL E. MERCER
    Michael E. Mercer 
    Senior Vice President and Chief Financial Officer 

 

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EXHIBIT INDEX 

 

3.1First Amended and Restated Partnership Agreement EV Energy Partners, L.P. (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.2First Amended and Restated Partnership Agreement of EV Energy GP, L.P. (incorporated by reference from Exhibit 3.2 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.3Amended and Restated Limited Liability Company Agreement of EV Management, LLC. (incorporated by reference from Exhibit 3.3 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on October 5, 2006).

 

3.4First Amendment dated April 15, 2008 to First Amended and Restated Partnership Agreement of EV Energy Partners, L.P., effective as of January 1, 2007 (incorporated by reference from Exhibit 3.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 18, 2008).

 

4.1Indenture, dated as of March 22, 2011, by and among EV Energy Partners, L.P., EV Energy Finance Corp., the Guarantors named therein and U.S. National Bank Association, as trustee (incorporated by reference from Exhibit 4.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on March 22, 2011).

 

10.1Sixth Amendment dated September 19, 2014 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on September 25, 2014).

 

+31.1Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer. 

 

+31.2Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer. 

 

+32.1Section 1350 Certification of Chief Executive Officer.  

 

+32.2Section 1350 Certification of Chief Financial Officer. 

 

+101Interactive Data Files. 

  

 

+ Filed herewith