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EX-32.2 - EXHIBIT 32.2 - Harvest Oil & Gas Corp.v451015_ex32-2.htm
EX-32.1 - EXHIBIT 32.1 - Harvest Oil & Gas Corp.v451015_ex32-1.htm
EX-31.2 - EXHIBIT 31.2 - Harvest Oil & Gas Corp.v451015_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - Harvest Oil & Gas Corp.v451015_ex31-1.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, 2016

OR

 

¨TRANSITION 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 ¨

 

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 ¨

 

     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 ¨   Non-accelerated filer ¨   Smaller reporting company ¨

   

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

YES ¨ NO þ

 

As of November 7, 2016, the registrant had 49,055,214 common units outstanding.

 

 

 

 

 

 

Table of Contents 

 

PART I.  FINANCIAL INFORMATION   2
       
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   25
Item 4. Controls and Procedures   26
       
PART II.  OTHER INFORMATION   26
       
Item 1. Legal Proceedings   26
Item 1A. Risk Factors   26
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds   26
Item 3. Defaults Upon Senior Securities   26
Item 4. Mine Safety Disclosures   26
Item 5. Other Information   26
Item 6. Exhibits   27
       
Signatures     28

 

 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, 
   2016   2015 
ASSETS          
Current assets:          
Cash and cash equivalents  $5,981   $20,415 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   37,803    24,285 
Other   2,216    7,137 
Derivative asset   10,043    60,662 
Other current assets   3,226    3,057 
Total current assets   59,269    115,556 
           
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2016, $1,062,990; December 31, 2015, $971,499   1,701,279    1,790,455 
Other property, net of accumulated depreciation and amortization;  September 30, 2016, $994; December 31, 2015, $970   1,010    1,019 
Long–term derivative asset   464    10,741 
Other assets   4,354    5,831 
Total assets  $1,766,376   $1,923,602 
           
LIABILITIES AND OWNERS’ EQUITY          
Current liabilities:          
Accounts payable and accrued liabilities:          
Third party  $40,278   $43,135 
Related party   5,224    5,952 
Income taxes   -    11,657 
Derivative liability   2,362    - 
Total current liabilities   47,864    60,744 
           
Asset retirement obligations   178,058    174,003 
Long–term debt, net   613,799    688,614 
Long–term derivative liability   3,056    - 
Other long–term liabilities   1,278    1,682 
           
Commitments and contingencies          
           
Owners’ equity:          
Common unitholders – 49,055,214 units and 48,871,399 units issued and outstanding as of September 30, 2016 and December 31, 2015, respectively   936,793    1,011,509 
General partner interest   (14,472)   (12,950)
Total owners’ equity   922,321    998,559 
Total liabilities and owners’ equity  $1,766,376   $1,923,602 

 

 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, 
   2016   2015   2016   2015 
Revenues:                    
Oil, natural gas and natural gas liquids revenues  $50,750   $37,587   $130,854   $127,734 
Transportation and marketing–related revenues   622    734    1,599    2,285 
Total revenues   51,372    38,321    132,453    130,019 
                     
Operating costs and expenses:                    
Lease operating expenses   25,571    22,509    80,532    69,833 
Cost of purchased natural gas   435    510    1,076    1,588 
Dry hole and exploration costs   294    1,034    1,195    1,720 
Production taxes   2,126    1,357    5,501    4,708 
Accretion expense on obligations   2,057    1,134    6,146    3,548 
Depreciation, depletion and amortization   31,639    23,485    91,492    74,718 
General and administrative expenses   8,514    8,609    24,862    28,968 
Impairment of oil and natural gas properties   687    15,787    3,371    122,244 
Gain on settlement of contract   -    -    (3,185)   - 
Gain on sales of oil and natural gas properties   -    -    -    (531)
Total operating costs and expenses   71,323    74,425    210,990    306,796 
                     
Operating loss   (19,951)   (36,104)   (78,537)   (176,777)
                     
Other income (expense), net:                    
Gain (loss) on derivatives, net   8,559    37,042    (17,192)   51,406 
Interest expense   (9,889)   (11,043)   (32,554)   (38,279)
Gain on early extinguishment of debt   -    -    47,695    - 
Other income, net   622    206    1,586    51 
Total other income (expense), net   (708)   26,205    (465)   13,178 
                     
Loss from continuing operations before income taxes   (20,659)   (9,899)   (79,002)   (163,599)
                     
Income taxes   1,429    61    1,779    684 
                     
Loss from continuing operations   (19,230)   (9,838)   (77,223)   (162,915)
                     
Income from discontinued operations   -    -    -    255,512 
                     
Net income (loss)  $(19,230)  $(9,838)  $(77,223)  $92,597 
                     
Basic and diluted earnings per limited partner unit:                    
Loss from continuing operations  $(0.38)  $(0.20)  $(1.54)  $(3.29)
Income from discontinued operations   -    -    -    5.12 
Net income (loss)  $(0.38)  $(0.20)  $(1.54)  $1.83 
                     
Weighted average limited partner units outstanding (basic and diluted)   49,055    48,871    49,046    48,846 
                     
Distributions declared per unit  $-   $0.50   $-   $1.50 

 

 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)

(Unaudited)

 

   Common
 Unitholders
   General Partner  
Interest
   Total Owners'  
Equity
 
             
Balance, December 31, 2015  $1,011,509   $(12,950)  $998,559 
Contributions from general partner   -    -    - 
Distributions   (3,793)   (75)   (3,868)
Equity–based compensation   4,756    97    4,853 
Net loss   (75,679)   (1,544)   (77,223)
Balance, September 30, 2016  $936,793   $(14,472)  $922,321 
                
    Common  
Unitholders
    General Partner  
Interest
    Total Owners'  
Equity
 
                
Balance, December 31, 2014  $1,077,826   $(11,713)  $1,066,113 
Contribution from general partner   -    91    91 
Distributions   (74,242)   (1,496)   (75,738)
Equity–based compensation   9,442    193    9,635 
Net income   90,745    1,852    92,597 
Balance, September 30, 2015  $1,103,771   $(11,073)  $1,092,698 

 

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, 
   2016   2015 
Cash flows from operating activities:          
Net income (loss)  $(77,223)  $92,597 
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:          
Income from discontinued operations   -    (255,512)
Amortization of volumetric production payment liability   (3,070)   - 
Accretion expense on obligations   6,146    3,548 
Depreciation, depletion and amortization   91,492    74,718 
Equity–based compensation cost   4,853    9,635 
Impairment of oil and natural gas properties   3,371    122,244 
Gain on sales of oil and natural gas properties   -    (531)
Loss (gain) on derivatives, net   17,192    (51,406)
Cash settlements of matured derivative contracts   46,299    98,368 
Gain on early extinguishment of debt   (47,695)   - 
Other   1,822    288 
Changes in operating assets and liabilities:          
Accounts receivable   (8,597)   13,864 
Other current assets   (291)   894 
Accounts payable and accrued liabilities   4,158    10,610 
Income taxes   (11,657)   - 
Other, net   (277)   (120)
Net cash flows provided by operating activities from continuing operations   26,523    119,197 
Net cash flows used in operating activities from discontinued operations   -    (372)
Net cash flows provided by operating activities   26,523    118,825 
           
Cash flows from investing activities:          
Additions to oil and natural gas properties   (14,266)   (58,687)
Deposit on acquisition of oil and natural gas properties   -    (25,900)
Proceeds from sale of oil and natural gas properties   2,420    1,439 
Cash settlements from acquired derivative contracts   2,823    - 
Restricted cash   -    33,768 
Other   33    48 
Net cash flows used in investing activities from continuing operations   (8,990)   (49,332)
Net cash flows provided by investing activities from discontinued operations   -    572,160 
Net cash flows (used in) provided by investing activities   (8,990)   522,828 
           
Cash flows from financing activities:          
Repayment of long-term debt borrowings   (41,000)   (561,000)
Long–term debt borrowings   48,000    30,000 
Redemption of Senior Notes due 2019   (34,978)   - 
Loan costs incurred   (121)   (3,400)
Contributions from general partner   -    91 
Distributions paid   (3,868)   (75,738)
Net cash flows used in financing activities   (31,967)   (610,047)
           
Increase (decrease) in cash and cash equivalents   (14,434)   31,606 
Cash and cash equivalents – beginning of year   20,415    8,255 
Cash and cash equivalents – end of period  $5,981   $39,861 

 

 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.

 

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 in this Form 10-Q. 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 the audited consolidated financial statements included in Item 8 of our Annual Report on Form 10–K for the year ended December 31, 2015.

 

All intercompany accounts and transactions have been eliminated in consolidation. In these 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.

 

Subsequent Events

 

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

 

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 of phantom units and performance units.

 

We estimated the fair value of the phantom units using the Black–Scholes option pricing model. Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures. These phantom units are subject to graded vesting over a four year period. We recognized compensation cost related to these phantom units of $1.9 million and $2.3 million in the three months ended September 30, 2016 and 2015, respectively, and $4.9 million and $9.4 million in the nine months ended September 30, 2016 and 2015, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

As of September 30, 2016, there was $9.2 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.1 years.

 

In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units were fully vested as of January 2015, and we recognized compensation cost related to these performance units of $0.2 million in the nine months ended September 30, 2015. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

 6 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 3. ACQUISITIONS

 

In October 2015, we made the following acquisitions from certain institutional partnerships managed by EnerVest, a related party:

 

·we acquired Belden & Blake Corporation (“Belden”) for $111.1 million;

 

·we acquired oil and natural gas properties in the Austin Chalk for $25.9 million; and

 

·we acquired oil and natural gas properties in the Appalachian Basin and the San Juan Basin for $122.0 million.

 

These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties.

 

As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements. Under these agreements, certain of these oil and natural gas properties are subject to fixed–term overriding royalty interests which had been conveyed to the VPP purchaser. While we are obligated under these agreements to produce and deliver to the purchaser its portion of future natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling. If production from the oil and natural gas properties subject to the VPP is inadequate to deliver the natural gas provided for in the VPP, we have an obligation to make up the shortfall in accordance with the provisions of the agreements. At September 30, 2016 and December 31, 2015, the remaining obligation under these agreements was approximately 0.5 Bcf and 1.9 Bcf, respectively, of natural gas.

 

At September 30, 2016 and December 31, 2015, we have recorded a liability of $1.0 million and $4.0 million, respectively, which is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets, for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. In the three months and nine months ended September 30, 2016, we recorded $0.02 million and $0.1 million, respectively, of accretion expense related to this VPP obligation.

 

We accounted for these acquisitions as business combinations. The following table reflects pro forma revenues and net income for the three months and nine months ended September 30, 2015 as if these acquisitions had taken place on January 1, 2015. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

 

   Three Months   Nine Months 
   Ended   Ended 
   September 30,   September 30, 
   2015   2015 
Revenues:          
Historical  $38,321   $130,019 
Belden   8,261    24,292 
Austin Chalk   2,609    9,235 
Appalachian and San Juan Basins   7,528    23,738 
Pro forma revenues  $56,719   $187,284 
           
Net income (loss):          
Historical  $(9,838)  $92,597 
Belden   (17,208)   (76,910)
Austin Chalk   (340)   1,218 
Appalachian and San Juan Basins   (241)   413 
Pro forma net income (loss)  $(27,627)  $17,318 

 

 7 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 4. 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, 2016, we had entered into commodity contracts with the following terms:

 

       Weighted   Weighted   Weighted 
       Average   Average   Average 
   Hedged   Fixed   Floor   Ceiling 
Period Covered  Volume   Price   Price   Price 
Oil (MBbls):                    
Swaps – October 2016 to December 2016   230.0   $65.99   $-   $- 
Collars – October 2016 to December 2016   138.0    -    45.00    54.05 
                     
Natural Gas (MmmBtus):                    
Swaps – October 2016 to December 2016   11,316.0    3.42    -    - 
Swaps – 2017   32,850.0    3.07    -    - 
Collars – 2017   10,950.0    -    2.75    3.27 
                     
Natural Gas Liquids (MBbls):                    
Swaps – October 2016 to December 2016   0.9    9.14    -    - 

 

 As of September 30, 2016, we had entered into interest rate swaps with the following terms:

 

Period Covered  Notional Amount   Floating Rate  Fixed Rate 
January 2017 – December 2017  $100,000   1 Month LIBOR   1.039%
January 2018 – September 2020   100,000   1 Month LIBOR   1.795%

 

 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, 2016:               
Derivative asset  $12,124   $(2,081)  $10,043 
Long–term derivative asset   755    (291)   464 
Total  $12,879   $(2,372)  $10,507 
                
As of December 31, 2015:               
Derivative asset  $60,662   $-   $60,662 
Long–term derivative asset   10,741    -    10,741 
Total  $71,403   $-   $71,403 

 

           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, 2016:               
Derivative liability  $4,443   $(2,081)  $2,362 
Long–term derivative liability   3,347    (291)   3,056 
Total  $7,790   $(2,372)  $5,418 

 

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, 2016 and December 31, 2015, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

 

NOTE 5. FAIR VALUE MEASUREMENTS

 

The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.

 

 9 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

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, 2016:                    
Assets - Oil, natural gas and natural gas liquids derivatives  $12,879   $   $12,879   $ 
                     
Liabilities:                    
Oil, natural gas and natural gas liquids derivatives  $5,688   $   $5,688   $ 
Interest rate swaps   2,102        2,102     
   $7,790   $   $7,790   $ 
                     
As of December 31, 2015:                    
Assets:                    
Oil, natural gas and natural gas liquids derivatives  $70,356   $   $70,356   $ 
Interest rate swaps   1,047        1,047     
   $71,403   $   $71,403   $ 

 

 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, 2016.

 

Nonrecurring Basis

 

In the three and nine months ended September 30, 2015, as a result of a reduction in estimated future net cash flows primarily caused by lower oil, natural gas and natural gas liquids prices, we recognized $15.2 million and $73.3 million, respectively, of impairment charges to write down oil and natural gas properties to their fair value of $10.4 million and $31.4 million in the three and nine months ended September 30, 2015, respectively.

 

The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data.

 

 10 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

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).

 

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 $232.6 million and $211.9 million at September 30, 2016 and December 31, 2015, respectively, which differs from the carrying value of $341.8 million and $423.6 million at September 30, 2016 and December 31, 2015, respectively. The fair value of the senior notes due 2019 was determined using Level 2 inputs.

 

NOTE 6. 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:

 

   2016   2015 
Balance as of January 1  $176,933   $105,773 
Liabilities incurred   420    394 
Revisions   227    (4,963)
Accretion expense   6,032    3,548 
Settlements and divestitures   (2,624)   (4,563)
Balance as of September 30  $180,988   $100,189 

 

As of both September 30, 2016 and December 31, 2015, $2.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

 

NOTE 7. LONG–TERM DEBT

 

Long–term debt, net consisted of the following:

 

   September 30,   December 31, 
   2016   2015 
         
Credit facility  $272,000   $265,000 
8.0% senior notes due 2019:          
  Principal outstanding   343,348    426,022 
  Unamortized discount and debt issuance costs (1)   (3,248)   (5,116)
  Unaccreted premium (2)   1,699    2,708 
    341,799    423,614 
Total  $613,799   $688,614 

 

 

(1)Imputed interest rate of 8.98% and 8.87% for September 30, 2016 and December 31, 2015, respectively.

 

(2)Imputed interest rate of 7.02% and 7.35% for September 30, 2016 and December 31, 2015, respectively.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Credit Facility

 

As of September 30, 2016, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties. The facility allows for up to $35.0 million in cash, reduced by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019 (see below) and limits cash held by us to the greater of 5% of the current borrowing base or $30.0 million. We also may use up to $100.0 million of available borrowing capacity for letters of credit. As of September 30, 2016, we have a $0.3 million letter of credit outstanding. The facility requires the maintenance of certain financial covenants, and, as of September 30, 2016, we were in compliance with these financial covenants.

 

The facility does not require any repayments of amounts outstanding until it expires in February 2020. 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 3.54% and 3.86% at September 30, 2016 and 2015, 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, 2016, the borrowing base under the facility was $450.0 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.

 

In October 2016, the borrowing base under the facility was reaffirmed at $450.0 million.

 

8.0% Senior Notes due 2019

 

Our senior notes due April 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 has independent assets or operations apart from the assets and operations of our subsidiaries.

 

In the nine months ended September 30, 2016, we redeemed $82.7 million of our senior notes due 2019 for $35.0 million, resulting in a gain on the early extinguishment of debt of $47.7 million.

 

NOTE 8. 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, 2016 or December 31, 2015.

 

NOTE 9. OWNERS’ EQUITY

 

Units Outstanding

 

At September 30, 2016, owners’ equity consists of 49,055,214 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

 

Issuance of Units

 

In January 2016, we issued 0.2 million common units related to the vesting of equity–based awards.

 

Cash Distributions

 

On January 25, 2016, the board of directors of EV Management declared a $0.075 per unit distribution for the fourth quarter of 2015 on all outstanding units. The distribution of $3.9 million was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

In April and May 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first and second quarters of 2016, respectively. The board of directors also elected to suspend distributions for the third quarter of 2016.

 

NOTE 10. DISCONTINUED OPERATIONS

 

In 2015, we reclassified our unaudited condensed consolidated financial statements to reflect the operations of our midstream segment as discontinued operations due to the sales of our interest in Cardinal Gas Services, LLC in October 2014 and our interest in Utica East Ohio Midstream LLC in June 2015.

 

Summarized financial information for our midstream segment is as follows:

 

   Three Months
Ended
   Nine Months
Ended
 
   September 30,   September 30, 
   2015   2015 
         
Revenues  $-   $93,726 
Operating income   -    49,171 
Net income   -    49,525 

 

 13 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

NOTE 11. EARNINGS PER LIMITED PARTNER UNIT

 

The following sets forth the calculation of earnings per limited partner unit:

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2016   2015   2016   2015 
Loss from continuing operations  $(19,230)  $(9,838)  $(77,223)  $(162,915)
General partner's 2% interest in loss from continuing operations   385    197    1,544    3,257 
Earnings attributable to unvested phantom units   -    (315)   -    (972)
Limited partners' interest in loss from continuing operations  $(18,845)  $(9,956)  $(75,679)  $(160,630)
                     
Earnings per limited partner unit (basic and diluted)  $(0.38)  $(0.20)  $(1.54)  $(3.29)
                     
Income from discontinued operations  $-   $-   $-   $255,512 
General partner's 2% interest in income from discontinued operations   -    -    -    (5,110)
Earnings attributable to unvested phantom units   -    -    -    (216)
Limited partners' interest in income from discontinued operations  $-   $-   $-   $250,186 
                     
Earnings per limited partner unit (basic and diluted)  $-   $-   $-   $5.12 
                     
Net income (loss)  $(19,230)  $(9,838)  $(77,223)  $92,597 
General partner’s 2% interest in net income (loss)   385    197    1,544    (1,852)
Earnings attributable to unvested phantom units   -    (315)   -    (1,188)
Limited partners’ interest in net income (loss)  $(18,845)  $(9,956)  $(75,679)  $89,557 
                     
Earnings per limited partner unit (basic and diluted)  $(0.38)  $(0.20)  $(1.54)  $1.83 
                     
Weighted average limited partner units outstanding (basic and diluted)   49,055    48,871    49,046    48,846 

 

NOTE 12. RELATED PARTY TRANSACTIONS

 

Pursuant to an omnibus agreement, we paid EnerVest $4.0 million and $3.3 million in the three months ended September 30, 2016 and 2015, respectively, and $12.0 million and $9.9 million in the nine months ended September 30, 2016 and 2015, 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.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

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 $5.3 million and $3.5 million in the three months ended September 30, 2016 and 2015, respectively, and $16.0 million and $11.3 million in the nine months ended September 30, 2016 and 2015, 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.

 

NOTE 13. OTHER SUPPLEMENTAL INFORMATION

 

Supplemental cash flows and noncash transactions were as follows: 

 

   Nine Months Ended 
   September 30, 
   2016   2015 
Supplemental cash flows information:          
Cash paid for interest  $23,543   $26,460 
Cash paid for income taxes, net of refunds   10,592    (115)

 

   As of September 30, 
   2016   2015 
         
Noncash transaction - costs for additions to oil and natural gas properties in          
accounts payable and accrued liabilities  $1,071   $6,872 

 

Accounts payable and accrued liabilities for third party consisted of the following:

 

   September 30,   December 31, 
   2016   2015 
Costs for additions to oil and natural gas properties  $1,071   $5,212 
Lease operating expenses   10,969    10,576 
Interest   12,910    7,298 
Production and ad valorem taxes   7,298    6,763 
VPP   1,029    3,984 
General and administrative expenses   2,476    2,864 
Current portion of ARO   2,930    2,930 
Derivative settlements   109    - 
Other   1,486    3,508 
Total  $40,278   $43,135 

 

NOTE 14. NEW ACCOUNTING STANDARDS

 

In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 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 the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

In February 2016, the FASB issued ASU No. 2016-02: Leases. The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. For public entities, ASU 2016-02 is effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. We will continue to assess the impact this may have on its financial position, results of operations, and cash flows.

 

In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation. This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

 

In August 2016, the FASB issued ASU No. 2016–15, Statement of Cash Flows. This ASU addresses certain cash flow issues with the objective of reducing the existing diversity in practice in how the cash receipts and cash payments are presented and classified in the statement of cash flows. The provisions of ASU 2016–15 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. 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, 2016 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

 

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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, 2015.

 

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 operate in one reportable segment engaged in the acquisition, development and production of oil and natural gas properties, and all of our operations are located in the United States.

 

As of December 31, 2015, our oil and natural gas properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, and the Permian Basin. As of December 31, 2015, we had estimated net proved reserves of 22.0 MMBbls of oil, 747.0 Bcf of natural gas and 36.3 MMBbls of natural gas liquids, or 1,096.7 Bcfe, and a standardized measure of $536.4 million.

 

Current Price Environment

 

Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and such prices have remained low into the nine months ended September 30, 2016.

 

Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices have fallen and are likely to continue to directionally follow the market for oil. Further, excess supply with higher volumes in storage has resulted in a further drop in pricing for natural gas liquids.

 

In the nine months ended September 30, 2016, these low prices negatively affected our revenues, earnings and cash flows, and sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. A further or extended decline in prices could also adversely have a significant impact on the value and quantities of our reserves, assuming no other changes in our development plans.

 

As specified by the SEC, the prices for oil, natural gas and natural gas liquids used to calculate our reserves were the average prices during the year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved reserves at December 31, 2015 were $50.28 per Bbl of oil and $2.587 per MMBtu of natural gas. Had we used the current forward strip prices at December 31, 2015 through December 31, 2021, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 29% higher and that our reserves on an Mcfe basis would have been approximately 7% higher than our reserves calculated using SEC prices.

 

Our Response to the Current Price Environment

 

In response to continued depressed prices and the fact that we have less production hedged in 2016 and 2017 at lower prices relative to previous years, we took a number of steps to continue to preserve our liquidity and financial flexibility. These steps include:

 

·reevaluating and suspending our common unit distribution to conserve excess cash;

 

·maintaining a sufficient liquidity position to manage through the current environment;

 

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·reducing the amount of capital spending we dedicate to the development of our reserves by approximately 75%;

 

·focusing on managing and enhancing our base business through continued reductions in operating and capital costs;

 

·continuing to evaluate strategic acquisitions of long–life, producing oil and natural gas properties; and

 

·further realizing the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.

 

In April 2016, we entered into an amendment to our credit facility that reduced our borrowing base, eased leverage covenants and added an interest coverage ratio. Specifically, the amendment:

 

·decreased the borrowing base to $450.0 million;

 

·changed the senior secured funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016, September 30, 2016 and December 31, 2016, 3.0 to 1.0, (b) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;

 

·changed the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2018, 5.50 to 1.0, (b) for the fiscal quarters ending June 30, 2018 and September 30, 2018, 5.25 to 1.0 and (c) for the fiscal quarter ending December 31, 2018 and thereafter, 4.25 to 1.0;

 

·added an EBITDAX to cash interest expense ratio covenant to be no less than (a) for the fiscal quarters ending March 31, 2016, June 30, 2016 and September 30, 2016, 2.5 to 1.0, (b) for the fiscal quarters ending December 31, 2016, March 31, 2017 and June 30, 2017, 2.0 to 1.0 and (c) for the fiscal quarter ending September 30, 2017 and thereafter, 1.5 to 1.0;

 

·allowed for up to $35.0 million of cash, reduced dollar for dollar by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019; and

 

·limited cash held by us to the greater of 5% of the current borrowing base or $30.0 million.

 

In April 2016, the board of directors announced that it had elected to suspend distributions to unitholders, and, since the adoption of this amendment in April 2016, we have reduced leverage by repurchasing $82.7 million of outstanding senior notes due 2019 for $35.0 million. This repurchase of our senior notes due 2019 at a discount to par created cancellation of debt income for our unitholders.

 

In October 2016, the borrowing base under the facility was reaffirmed at $450.0 million. As of November 7, 2016, we had $281.0 million outstanding under our credit facility and $343.3 million of our senior notes due 2019 outstanding, for a total of $624.3 million, and we had $177.7 million of liquidity between our borrowing base capacity and cash on hand.

 

Business Environment

 

Our primary business objective is to provide stability and growth in cash distributions per unit over time. We have currently suspended distributions to unitholders to conserve any excess cash to enable us to be able to pay a distribution at a future date. When we resume our distribution payments, the amount of cash we could distribute to our unitholders will principally depend 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 amount of oil, natural gas liquids and natural gas we produce; and

 

·the level of our operating and administrative costs.

 

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In order to mitigate the impact of lower 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. We have entered into derivative contracts covering a portion of our future production through December 2017; however, due to depressed commodity prices over the last 2 years and the unfavorable terms of available hedging contracts, we have less production volumes hedged and the prices at which those volumes are hedged are at lower average prices than in the past. This has left us with a greater exposure to current commodity prices and has impacted cash flows from operations. Continued depressed commodity prices could continue to impact our acquisition and development plans, our growth strategy and our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions, which may delay our ability to reinstate our quarterly distribution.

 

The primary factors affecting our production levels are capital availability, including planned reductions in capital spending for 2016, 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 future possible distributions.

 

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.

 

RESULTS OF OPERATIONS

 

   Three Months Ended   Nine Months Ended 
   September 30,   September 30, 
   2016   2015   2016   2015 
Production data:                    
Oil (MBbls)   308    212    938    690 
Natural gas liquids (MBbls)   597    526    1,784    1,671 
Natural gas (MMcf)   12,535    9,720    38,304    30,326 
Net production (MMcfe)   17,965    14,147    54,637    44,491 
Average sales price per unit:                    
Oil (Bbl)  $40.40   $41.27   $36.82   $46.19 
Natural gas liquids (Bbl)   14.23    11.93    14.09    14.11 
Natural gas (Mcf)   2.38    2.32    1.86    2.38 
Mcfe   2.82    2.66    2.39    2.87 
Average unit cost per Mcfe:                    
Production costs:                    
Lease operating expenses  $1.42   $1.59   $1.47   $1.57 
Production taxes   0.12    0.10    0.10    0.11 
Total   1.54    1.69    1.57    1.68 
Depreciation, depletion and amortization   1.76    1.66    1.67    1.68 
General and administrative expenses   0.47    0.61    0.46    0.66 

 

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Three Months Ended September 30, 2016 Compared with the Three Months Ended September 30, 2015

 

Net loss for the three months ended September 30, 2016 was $19.2 million compared with $9.8 million for the three months ended September 30, 2015. The significant factors in this change were (i) a $28.5 million unfavorable change in gain (loss) on derivatives, partially offset by (ii) a $15.1 million decrease in impairment of oil and natural gas properties.

 

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2016 totaled $50.8 million, an increase of $13.2 million compared with the three months ended September 30, 2015. This was the result of an increase of $11.6 million from increased oil, natural gas and natural gas liquids production and $1.8 million from higher natural gas and natural gas liquids prices, partially offset by $0.2 million related to lower prices for oil. 

 

Lease operating expenses for the three months ended September 30, 2016 increased $3.1 million compared with the three months ended September 30, 2015 as the result of $5.4 million from increased production offset by $2.3 million from a lower unit cost per Mcfe. Lease operating expenses were $1.42 per Mcfe in the three months ended September 30, 2016 compared with $1.59 per Mcfe in the three months ended September 30, 2015. 

  

Depreciation, depletion and amortization (“DD&A”) for the three months ended September 30, 2016 increased $8.2 million compared with the three months ended September 30, 2015 as a result of $6.7 million from increased production and $1.5 million from a higher unit cost per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A was $1.76 per Mcfe in the three months ended September 30, 2016 compared with $1.66 per Mcfe in the three months ended September 30, 2015. 

 

General and administrative (“G&A”) expenses for the three months ended September 30, 2016 totaled $8.5 million compared with $8.6 million for the three months ended September 30, 2015. Included in G&A expenses for the three months ended September 30, 2016 were $0.5 million of lower due diligence costs related to the October 2015 acquisitions costs recorded during 2015 and $0.4 million of lower equity compensation costs, partially offset by $0.7 million of higher fees paid to EnerVest under the omnibus agreement. G&A expenses were $0.47 per Mcfe in the three months ended September 30, 2016 compared with $0.61 per Mcfe in the three months ended September 30, 2015.

 

In the three months ended September 30, 2016, we incurred leasehold impairment charges of $0.7 million. In the three months ended September 30, 2015, we incurred impairment charges of $15.8 million, of which $15.2 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk-adjusted discount rates and other relevant data. The remainder of the impairment charges for the three months ended September 30, 2015 consisted of $0.6 million of leasehold impairments related to a change in our development plans for acreage in the Utica Shale.

 

Gain on derivatives, net was $8.6 million for the three months ended September 30, 2016 compared with $37.0 million for the three months ended September 30, 2015. This change was attributable to changes in future oil and natural gas prices and the impact of the expiration of derivative contracts with more favorable terms as of December 31, 2015. The 12 month forward price at September 30, 2016 for oil averaged $50.65 per Bbl compared with $49.42 at June 30, 2016, and the 12 month forward prices at September 30, 2016 for natural gas averaged $3.07 per MmBtu compared with $3.02 at June 30, 2016. The 12 month forward price at September 30, 2015 for oil averaged $48.71 per Bbl compared with $61.99 at June 30, 2015, and the 12 month forward prices at September 30, 2015 for natural gas averaged $2.82 per MmBtu compared with $3.13 at June 30, 2015.

 

Interest expense for the three months ended September 30, 2016 decreased $1.2 million compared with the three months ended September 30, 2015 due to $3.1 million from a lower weighted average effective interest rate, partially offset by $1.9 million from a higher weighted average long–term debt balance.

 

Nine Months Ended September 30, 2016 Compared with the Nine Months Ended September 30, 2015

 

Net income (loss) for the nine months ended September 30, 2016 was $(77.2) million compared with $92.6 million for the nine months ended September 30, 2015. The significant factors in this change were (i) a $255.5 million decrease in income from discontinued operations and (ii) a $68.6 million unfavorable change in gain (loss) on derivatives, partially offset by (iii) a $47.7 million gain on early extinguishment of debt and (iv) a $118.9 million decrease in impairment of oil and natural gas properties.

 

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Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2016 totaled $130.9 million, an increase of $3.1 million compared with the nine months ended September 30, 2015. This was the result of an increase of $25.5 million for increased production, partially offset by $22.4 million related to lower prices. 

 

Lease operating expenses for the nine months ended September 30, 2016 increased $10.7 million compared with the nine months ended September 30, 2015 as the result of $15.0 million from increased production partially offset by $4.3 million from a lower unit cost per Mcfe. Lease operating expenses were $1.47 per Mcfe in the nine months ended September 30, 2016 compared with $1.57 per Mcfe in the nine months ended September 30, 2015.

  

DD&A for the nine months ended September 30, 2016 increased $16.8 million compared with the nine months ended September 30, 2015 as a result of $17.0 million from increased production partially offset by $0.2 million from a lower unit cost per Mcfe. 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 2015. DD&A was $1.67 per Mcfe in the nine months ended September 30, 2016 compared with $1.68 per Mcfe in the nine months ended September 30, 2015.

 

G&A expenses for the nine months ended September 30, 2016 totaled $24.9 million, a decrease of $4.1 million compared with the nine months ended September 30, 2015. This decrease is primarily the result of (i) $4.8 million of lower equity compensation costs, of which $2.3 million related to the accelerated vesting of the phantom units of a former officer in the nine months ended September 30, 2015; (ii) a $1.3 million decrease in compensation costs, of which $0.8 million related to the vesting of our phantom units under our equity compensation plan; partially offset by (iii) $2.1 million of higher fees paid to EnerVest under the omnibus agreement. G&A expenses were $0.46 per Mcfe in the nine months ended September 30, 2016 compared with $0.66 per Mcfe in the nine months ended September 30, 2015.

 

In the nine months ended September 30, 2016, we incurred leasehold impairment charges of $3.4 million. In the nine months ended September 30, 2015, we incurred impairment charges of $122.2 million. Of this amount, $73.3 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk adjusted discount rates and other relevant data. The remainder of the impairment charges for the nine months ended September 30, 2015 consisted of $48.9 million of leasehold impairments, of which $48.4 million related to a change in our development plans for acreage in the Utica Shale.

 

Gain (loss) on derivatives, net was $(17.2) million for the nine months ended September 30, 2016 compared with $51.4 million for the nine months ended September 30, 2015. This change was attributable to changes in future oil and natural gas prices and the impact of the expiration of derivative contracts with more favorable terms. The 12 month forward price at September 30, 2016 for oil averaged $50.65 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at September 30, 2016 for natural gas averaged $3.07 per MmBtu compared with $2.49 at December 31, 2015. The 12 month forward price at September 30, 2015 for oil averaged $48.71 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at September 30, 2015 for natural gas averaged $2.82 per MmBtu compared with $3.03 at December 31, 2014.

 

Interest expense for the nine months ended September 30, 2016 decreased $5.7 million compared with the nine months ended September 30, 2015 due to $8.0 million from a lower weighted average long–term debt balance, partially offset by $0.8 million from a higher weighted average effective interest rate and the write–off of $1.5 million of loan costs due to the reduction in the borrowing base and the redemption of the senior notes due 2019.

 

In the nine months ended September 30, 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our senior notes due 2019 for $35.0 million.

 

In the nine months ended September 30, 2015, income from discontinued operations was $255.5 million, which included the $246.7 million gain on the sale of UEO.

 

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, distributions to our unitholders and general partner and working capital needs.

 

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In response to continued depressed prices and the fact that we have less production hedged in 2016 and 2017 at lower prices relative to previous years, we took a number of steps to continue to preserve our liquidity and financial flexibility. These steps include:

 

·reevaluating and suspending our common unit distribution to conserve excess cash;

 

·maintaining a sufficient liquidity position to manage through the current environment;

 

·reducing the amount of capital spending we dedicate to the development of our reserves by approximately 75%;

 

·focusing on managing and enhancing our base business through continued reductions in operating and capital costs;

 

·continuing to evaluate strategic acquisitions of long–life, producing oil and natural gas properties; and

 

·further realizing the value of our undeveloped acreage through either alternative sources of capital, including farmouts, production payments and joint ventures, or potential monetization of acreage.

 

As of November 7, 2016, we had $177.7 million of liquidity between our borrowing base capacity and cash on hand. We believe that this available capital, coupled with net cash flows generated from operations and any proceeds from sales of assets will be adequate to fund our capital budget for the remainder of the year 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, 2016, we have a $1.0 billion credit facility that expires in February 2020. 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, 2016, the borrowing base was $450.0 million, and we had $272.0 million outstanding. In October 2016, the borrowing base under the facility was reaffirmed at $450.0 million.

 

As of September 30, 2016, we had $343.3 million in aggregate principal amount outstanding of our senior notes due 2019. As of September 30, 2016, the aggregate carrying amount of the senior notes due 2019 was $341.8 million.

 

For additional information about our long–term debt, such as interest rates and covenants, please see Note 7 to our Unaudited Condensed Consolidated Financial Statements – “Long-Term Debt” contained herein.

 

Cash and Short–term Investments

 

At September 30, 2016, we had $6.0 million of cash on hand. 

 

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, 2016, all of our counterparties had performed pursuant to their derivative contracts.

 

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Cash Flows

 

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

 

   Nine Months Ended
September 30,
 
   2016   2015 
Operating activities  $26,523   $118,825 
Investing activities   (8,990)   522,828 
Financing activities   (31,967)   (610,047)

 

Operating Activities

 

Cash flows from operating activities provided $26.5 million and $118.8 million in the nine months ended September 30, 2016 and 2015, respectively. The significant factors in the change were $52.1 million of decreased cash settlements from our matured derivative contracts, an $11.7 million federal tax payment related to the conversion of an acquired corporation to a single member LLC and a $30.1 million change in working capital, primarily related to higher accounts receivable as a result of higher oil, natural gas and natural gas liquids production during the nine months ended September 30, 2016, partially offset by a $1.4 million income tax refund associated with one of our partnerships.

 

Investing Activities

 

During the nine months ended September 30, 2016, we spent $14.3 million for additions to our oil and natural gas properties and received $2.4 million from the sale of certain oil and natural gas wells and $2.8 million in cash settlements from acquired derivative contracts. During the nine months ended September 30, 2015, cash flows used in investing activities from continuing operations totaled $49.3 million. This consisted of $58.7 million for additions to our oil and natural gas properties and $25.9 million related to a deposit on our October 2015 acquisition offset by $33.8 million from the release of cash deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code and $1.4 million in proceeds from the sale of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $572.2 million consisted of the proceeds from the sale of our interest in Utica East Ohio Midstream LLC (“UEO”).

 

Financing Activities

 

During the nine months ended September 30, 2016, we received $48.0 million from borrowings under our credit facility, repaid $41.0 million of long–term debt borrowings, and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner. We also redeemed $82.7 million of our senior notes due 2019 for $35.0 million.

 

During the nine months ended September 30, 2015, we repaid $561.0 million of borrowings under our credit facility with proceeds from the sale of our investment in UEO and the release of our restricted cash. We also received $30.0 million from borrowings under our credit facility, incurred loan costs of $3.4 million related to the amendment of our credit facility and paid distributions of $75.7 million to holders of our common units, phantom units and our general partner.

 

Off Balance Sheet Arrangements

 

In the normal course of business, we may enter into off-balance sheet arrangements that can give rise to off-balance sheet obligations. Other than the off-balance sheet arrangements included in our 2015 Form 10-K, we have no other off-balance sheet arrangements that are reasonably likely to materially affect our liquidity or availability of or requirements for capital resources.

 

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:

 

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·our future financial and operating performance and results, and our ability to pay distributions;

 

·our business strategy and plans, and future capital expenditures, including plans to further realize value of our undeveloped acreage;

 

·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 and the length of time commodity prices remain depressed;

 

·significant disruptions in the financial markets;

 

·future capital requirements and availability of financing;

 

·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;

 

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

 

·developments in oil and natural gas producing countries;

 

·competition;

 

·general economic conditions;

 

·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.

 

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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, 2015.

 

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, commodity contracts 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 commodity contracts to hedge a portion of our anticipated oil and natural gas production through December 2017. As of September 30, 2016, we have commodity contracts covering approximately 69% of our production attributable to our estimated net proved reserves from October 2016 through December 2017, 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 commodity contracts at September 30, 2016 was a net asset of $7.2 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 commodity contracts of approximately $14.7 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

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, 2016 would have increased by approximately $2.0 million. The fair value of our interest rate swaps at September 30, 2016 was a liability of $2.1 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 $1.5 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

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ITEM 4.CONTROLS AND PROCEDURES

 

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, 2016 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, 2016 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, 2015.

 

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

 

None.

 

ITEM 3.DEFAULTS UPON SENIOR SECURITIES

 

None.

 

ITEM 4.MINE SAFETY DISCLOSURES

 

Not applicable.

 

ITEM 5.OTHER INFORMATION

 

None.

 

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ITEM 6.EXHIBITS

 

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

 

3.1   First Amended and Restated Partnership Agreement of 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).
     
3.2   First 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).
     
3.3   Amended 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).
     
3.4   First 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).
     
4.1   Indenture, 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).
     
10.1   EV Energy Partners, L.P., 2016 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Definitive Proxy Statement filed on July 20, 2016).
     
+31.1   Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.
     
+31.2   Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.
     
+32.1   Section 1350 Certification of Chief Executive Officer.
     
+32.2   Section 1350 Certification of Chief Financial Officer.
     
+101   Interactive Data Files.

 ________________ 

+ Filed herewith

 

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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 8, 2016 By: /s/ NICHOLAS BOBROWSKI
    Nicholas Bobrowski
    Vice President and Chief Financial Officer

 

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EXHIBIT INDEX 

 

3.1 First Amended and Restated Partnership Agreement of 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).
   
3.2 First 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).
   
3.3 Amended 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).
   
3.4 First 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).
   
4.1 Indenture, 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).
   
10.1 EV Energy Partners, L.P., 2016 Long-Term Incentive Plan (incorporated by reference to Exhibit A to the Definitive Proxy Statement filed on July 20, 2016).
   
+31.1 Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.
   
+31.2 Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.
   
+32.1 Section 1350 Certification of Chief Executive Officer.
   
+32.2 Section 1350 Certification of Chief Financial Officer.
   
+101 Interactive Data Files.

 

 

+ Filed herewith

 

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