Attached files

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EX-31.1 - EXHIBIT 31.1 - Harvest Oil & Gas Corp.v417101_ex31-1.htm
EX-10.1 - EXHIBIT 10.1 - Harvest Oil & Gas Corp.v417101_ex10-1.htm
EX-31.2 - EXHIBIT 31.2 - Harvest Oil & Gas Corp.v417101_ex31-2.htm
EX-10.5 - EXHIBIT 10.5 - Harvest Oil & Gas Corp.v417101_ex10-5.htm
EX-10.4 - EXHIBIT 10.4 - Harvest Oil & Gas Corp.v417101_ex10-4.htm
EX-10.2 - EXHIBIT 10.2 - Harvest Oil & Gas Corp.v417101_ex10-2.htm
EX-10.3 - EXHIBIT 10.3 - Harvest Oil & Gas Corp.v417101_ex10-3.htm
EX-32.1 - EXHIBIT 32.1 - Harvest Oil & Gas Corp.v417101_ex32-1.htm
EX-32.2 - EXHIBIT 32.2 - Harvest Oil & Gas Corp.v417101_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 June 30, 2015 

 

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 July 31, 2015, the registrant had 48,871,399 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 16
Item 3. Quantitative and Qualitative Disclosures About Market Risk 24
Item 4. Controls and Procedures 25
     
  PART II.  OTHER INFORMATION 25
     
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 25
Item 4. Mine Safety Disclosures 25
Item 5. Other Information 25
Item 6. Exhibits 25
   
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)

 

   June 30,   December 31, 
   2015   2014 
ASSETS          
Current assets:          
Cash and cash equivalents  $58,813   $8,255 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   28,425    32,758 
Related party   -    1,043 
Other   3,596    4,570 
Derivative asset   72,683    113,044 
Other current assets   1,549    2,000 
Assets held for sale   -    315,173 
Total current assets   165,066    476,843 
           
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization;
June 30, 2015, $888,073; December 31, 2014, $778,679
   1,589,324    1,710,925 
Other property, net of accumulated depreciation and amortization; June 30, 2015, $917; December 31, 2014, $898   1,104    1,141 
Restricted cash   -    33,768 
Long–term derivative asset   12,895    20,647 
Other assets   7,161    5,879 
Total assets  $1,775,550   $2,249,203 
           
LIABILITIES AND OWNERS’ EQUITY          
Current liabilities:          
Accounts payable and accrued liabilities:          
Third party  $37,190   $47,878 
Related party   7,344    - 
Total current liabilities   44,534    47,878 
           
Asset retirement obligations   105,657    103,832 
Long–term debt   499,444    1,030,391 
Other long–term liabilities   477    989 
           
Commitments and contingencies          
           
Owners’ equity:          
Common unitholders – 48,871,399 units and 48,572,019 units issued and outstanding as of June 30, 2015 and December 31, 2014, respectively   1,135,862    1,077,826 
General partner interest   (10,424)   (11,713)
Total owners’ equity   1,125,438    1,066,113 
Total liabilities and owners’ equity  $1,775,550   $2,249,203 

 

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   Six Months Ended 
   June 30,   June 30, 
   2015   2014   2015   2014 
Revenues:                    
Oil, natural gas and natural gas liquids revenues  $43,722   $88,125   $90,147   $182,199 
Transportation and marketing–related revenues   734    1,235    1,551    2,500 
Total revenues   44,456    89,360    91,698    184,699 
                     
Operating costs and expenses:                    
Lease operating expenses   23,800    26,028    47,324    51,423 
Cost of purchased natural gas   504    942    1,078    1,912 
Dry hole and exploration costs   272    1,653    686    1,971 
Production taxes   1,603    2,957    3,351    6,480 
Asset retirement obligations accretion expense   1,213    1,203    2,414    2,390 
Depreciation, depletion and amortization   25,337    25,026    51,233    51,238 
General and administrative expenses   7,944    12,749    20,359    25,047 
Impairment of oil and natural gas properties   48,284    1,069    106,457    1,321 
Loss (gain) on sales of oil and natural gas properties   6    -    (531)   (1,484)
Total operating costs and expenses   108,963    71,627    232,371    140,298 
                     
Operating (loss) income   (64,507)   17,733    (140,673)   44,401 
                     
Other (expense) income, net:                    
(Loss) gain on derivatives, net   (9,246)   (17,817)   14,364    (40,812)
Interest expense   (13,101)   (12,445)   (27,236)   (24,517)
Other income (expense), net   41    206    (155)   380 
Total other expense, net   (22,306)   (30,056)   (13,027)   (64,949)
                     
Loss from continuing operations before income taxes   (86,813)   (12,323)   (153,700)   (20,548)
                     
Income taxes   473    78    623    333 
                     
Loss from continuing operations   (86,340)   (12,245)   (153,077)   (20,215)
                     
Income from discontinued operations   250,442    3,222    255,512    4,939 
                     
Net income (loss)  $164,102   $(9,023)  $102,435   $(15,276)
                     
Basic and diluted earnings per limited partner unit:                    
Loss from continuing operations  $(1.74)  $(0.26)  $(3.08)  $(0.43)
Income from discontinued operations   4.99    0.07    5.11    0.10 
Net income (loss)  $3.25   $(0.19)  $2.03   $(0.33)
                     
Weighted average limited partner units outstanding (basic and diluted)   48,871    48,572    48,833    48,555 
                     
Distributions declared per unit  $0.50   $0.769   $1.00   $1.537 

 

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, 2014  $1,077,826   $(11,713)  $1,066,113 
Contributions from general partner   -    91    91 
Distributions   (49,498)   (997)   (50,495)
Equity–based compensation   7,148    146    7,294 
Net income   100,386    2,049    102,435 
Balance, June 30, 2015  $1,135,862   $(10,424)  $1,125,438 

 

   Common
Unitholders
   General Partner
Interest
   Total Owners'
Equity
 
             
Balance, December 31, 2013  $1,083,718   $(11,785)  $1,071,933 
Contribution from general partner   -    154    154 
Distributions   (75,883)   (1,529)   (77,412)
Other   (5)       (5)
Equity–based compensation   10,837    221    11,058 
Net loss   (14,971)   (305)   (15,276)
Balance, June 30, 2014  $1,003,696   $(13,244)  $990,452 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 4 

 

 

EV Energy Partners, L.P.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

   Six Months Ended 
   June 30, 
   2015   2014 
Cash flows from operating activities:          
Net income (loss)  $102,435   $(15,276)
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:          
Income from discontinued operations   (255,512)   (4,939)
Asset retirement obligations accretion expense   2,414    2,390 
Depreciation, depletion and amortization   51,233    51,238 
Equity–based compensation cost   7,294    11,058 
Impairment of oil and natural gas properties   106,457    1,321 
Gain on sales of oil and natural gas properties   (531)   (1,484)
(Gain) loss on derivatives, net   (14,364)   40,812 
Cash settlements of matured derivative contracts   62,477    (11,555)
Other   890    1,271 
Changes in operating assets and liabilities:          
Accounts receivable   6,350    (12,978)
Other current assets   457    (813)
Accounts payable and accrued liabilities   4,714    2,478 
Other, net   (583)   (243)
Net cash flows provided by operating activities from continuing operations   73,731    63,280 
Net cash flows used in operating activities from discontinued operations   (372)   - 
Net cash flows provided by operating activities   73,359    63,280 
           
Cash flows from investing activities:          
Additions to oil and natural gas properties   (44,854)   (44,865)
Prepaid drilling costs   -    (2,346)
Proceeds from sale of oil and natural gas properties   774    7,315 
Restricted cash   33,768    - 
Other   32    34 
Net cash flows used in investing activities from continuing operations   (10,280)   (39,862)
Net cash flows provided by (used in) investing activities from discontinued operations   572,160    (83,188)
Net cash flows provided by (used in) investing activities   561,880    (123,050)
           
Cash flows from financing activities:          
Repayment of long-term debt borrowings   (561,000)   - 
Long–term debt borrowings   30,000    144,000 
Loan costs incurred   (3,277)   - 
Contributions from general partner   91    154 
Distributions paid   (50,495)   (77,412)
Other   -    (5)
Net cash flows (used in) provided by financing activities   (584,681)   66,737 
           
Increase in cash and cash equivalents   50,558    6,967 
Cash and cash equivalents – beginning of year   8,255    11,698 
Cash and cash equivalents – end of period  $58,813   $18,665 

 

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 indirect 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 an indirect 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.

 

With the sale of our interest in Cardinal Gas Services, LLC (“Cardinal”) in October 2014 and the sale of our interest in Utica East Ohio Midstream LLC (“UEO”) in June 2015, we no longer operate in the midstream segment, and we have reclassified our condensed consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations (see Note 9). We now 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.

 

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, 2014.

 

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 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 $2.3 million and $5.0 million in the three months ended June 30, 2015 and 2014, respectively, and $7.1 million and $8.1 million in the six months ended June 30, 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

As of June 30, 2015, there was $17.0 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.5 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. We recognized compensation cost related to these performance units of $0.2 million in the six months ended June 30, 2015 and $1.6 million and $2.9 million in the three months and six months ended June 30, 2014, respectively. 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. 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 “(Loss) gain on derivatives, net” in our unaudited condensed consolidated statements of operations.

 

As of June 30, 2015, we had entered into commodity contracts with the following terms:

 

Period Covered  Hedged Volume   Weighted Average
Fixed Price
 
Oil (MBbls):          
Swaps – July 2015 to December 2015   644.0   $90.28 
Swaps – 2016   366.0    90.14 
           
Natural Gas (MmmBtus):          
Swaps – July 2015 to December 2015   19,964.0    4.86 
Swaps – 2016   18,300.0    4.07 
           
Natural Gas Liquids (MBbls):          
Swaps – July 2015 to December 2015   239.2    24.98 

 

 7 

 

 

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 June 30, 2015:               
Derivative asset  $72,683   $-   $72,683 
Long–term derivative asset   12,895    -    12,895 
Total  $85,578   $-   $85,578 
                
As of December 31, 2014:               
Derivative asset  $114,754   $(1,710)  $113,044 
Long–term derivative asset   20,647    -    20,647 
Total  $135,401   $(1,710)  $133,691 

 

           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 December 31, 2014:               
Derivative liability  $1,710   $(1,710)  $- 
Long–term derivative liability   -    -    - 
Total  $1,710   $(1,710)  $- 

 

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 June 30, 2015 and December 31, 2014, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

 

NOTE 4. IMPAIRMENT OF OIL AND NATURAL GAS PROPERTIES

 

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. We recorded impairment charges of $58.2 million in the six months ended June 30, 2015 related to proved oil and natural gas properties (see Note 5).

 

 8 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized. We recorded impairment charges of $48.3 million in the three months and six months ended June 30, 2015 related to unproved oil and natural gas properties, of which $47.9 million related to a change in our development plans for acreage in the Utica Shale.

 

NOTE 5. 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 June 30, 2015:                    
Assets - Oil, natural gas and natural gas liquids derivatives  $85,578   $-   $85,578   $- 
                     
As of December 31, 2014:                    
Assets - Oil and natural gas derivatives  $135,401   $-   $135,401   $- 
                     
Liabilities - Interest rate swaps  $1,710   $-   $1,710   $- 

 

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 six months ended June 30, 2015.

 

Nonrecurring Basis

 

In the six months ended June 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 a $58.2 million impairment charge to write down oil and natural gas properties to their fair value of $31.4 million.

 

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 proved reserves, appropriate risk–adjusted discount rates and other relevant data.

 

 9 

 

 

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 $465.0 million and $427.5 million at June 30, 2015 and December 31, 2014, respectively, which differs from the carrying value of $499.4 million at both June 30, 2015 and December 31, 2014. 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:

 

 

   2015   2014 
Balance as of January 1  $105,773   $103,173 
Liabilities incurred   367    393 
Revisions   (1)   - 
Accretion expense   2,414    2,390 
Settlements and divestitures   (955)   (2,034)
Balance as of June 30  $107,598   $103,922 

 

As of both June 30, 2015 and December 31, 2014, $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.

 

NOTE 7. LONG–TERM DEBT

 

Credit Facility

 

As of June 30, 2015, 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. 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 June 30, 2015, 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 3.50% and 2.99% at June 30, 2015 and 2014, 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. Upon the sale of our interest in UEO, the borrowing base under our facility was reduced by $150.0 million and, as of June 30, 2015, the borrowing base under the facility was $500.0 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.

 

 10 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

 

As of June 30, 2015, we had no amounts outstanding under the facility. As of December 31, 2014, we had $531.0 million outstanding under the facility.

 

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 at both June 30, 2015 and December 31, 2014, respectively.

 

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 June 30, 2015 or December 31, 2014.

 

NOTE 9. OWNERS’ EQUITY

 

Units Outstanding

 

At June 30, 2015, owners’ equity consists of 48,871,399 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

 

Issuance of Units

 

In the six months ended June 30, 2015, we issued 0.3 million common units related to the vesting of equity–based awards. In conjunction with the vesting of these units, we received a contribution of $0.1 million by our general partner to maintain its 2% interest in us.

 

Cash Distributions

 

The following sets forth the distributions we paid during the six months ended June 30, 2014:

 

Date Paid  Period Covered  Distribution per Unit   Total Distribution 
February 13, 2015  October 1, 2014 – December 31, 2014  $0.50   $25,274 
May 15, 2015  January 1, 2015 – March 31, 2015   0.50    25,221 
           $50,495 

 

On July 30, 2015, the board of directors of EV Management declared a $0.50 per unit distribution for the second quarter of 2015 on all common units. The distribution of $25.2 million is to be paid on August 14, 2015 to unitholders of record at the close of business on August 10, 2015.

 

NOTE 10. DISCONTINUED OPERATIONS

 

Our midstream segment, which consisted of our investments in UEO and Cardinal, was 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 interest in Cardinal. In June 2015, we sold our interest in UEO and received net proceeds of $572.2 million and recognized a gain of $246.7 million. This gain is included in “Income from discontinued operations” for the three months and six months ended June 30, 2015.

 

 11 

 

 

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

As a result of the reduction in the borrowing base under our facility upon the sale of our interest in UEO, we were required to repay $25.0 million of outstanding borrowings. Accordingly, $1.5 million of interest related to this $25.0 million and the write off of deferred financing costs related to the reduction in the borrowing base have been allocated to “Income from discontinued operations.”

 

We have reclassified our unaudited condensed consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations. Accordingly, in our unaudited condensed consolidated balance sheets, amounts previously included in “Investments in unconsolidated affiliates” have been reclassified to ”Assets held for sale” and, in our unaudited condensed consolidated statement of operations, amounts previously included in “Equity in income of unconsolidated affiliates” have been reclassified to “Income from discontinued operations.”

 

Summarized financial information for our midstream segment is as follows:

 

 

   December 31,
2014 (1)
 
     
Current assets  $98,061 
Noncurrent assets   1,381,773 
      
Total assets  $1,479,834 
      
Current liabilities  $37,967 
Owner’s equity   1,441,867 
      
Total liabilities and owner’s equity  $1,479,834 

 

   Three Months Ended   Six Months Ended 
   June 30,   June 30, 
   2015 (1)   2014 (2)   2015 (1)   2014 (2) 
                 
Revenues  $45,183   $59,606   $93,726   $101,795 
Operating income   24,697    23,504    49,171    37,401 
Net income   24,781    23,537    49,525    37,468 

 

 

(1)Information is for UEO on a stand–alone basis through the date of divestiture.

 

(2)Information is for UEO and Cardinal on a combined basis.

 

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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   Six Months Ended 
   June 30,   June 30, 
   2015   2014   2015   2014 
Loss from continuing operations  $(86,340)  $(12,245)  $(153,077)  $(20,215)
General partner’s 2% interest in loss from continuing operations   1,727    244    3,061    404 
Loss from continuing operations attributable to unvested phantom units   (315)   (454)   (657)   (937)
Limited partners’ interest in loss from continuing operations  $(84,928)  $(12,455)  $(150,673)  $(20,748)
                     
Earnings per limited partner unit (basic and diluted)  $(1.74)  $(0.26)  $(3.08)  $(0.43)
                     
Income from discontinued operations  $250,442   $3,222   $255,512   $4,939 
General partner’s 2% interest in income from discontinued operations   (5,009)   (64)   (5,110)   (99)
Income from discontinued operations attributable to unvested phantom units   (1,732)   -    (675)   - 
Limited partners’ interest in income from discontinued operations  $243,701   $3,158   $249,727   $4,840 
                     
Earnings per limited partner unit (basic and diluted)  $4.99   $0.07   $5.11   $0.10 
                     
Net income (loss)  $164,102   $(9,023)  $102,435   $(15,276)
General partner’s 2% interest in net income (loss)   (3,282)   180    (2,049)   305 
Net income (loss) attributable to unvested phantom units   (2,047)   (454)   (1,332)   (937)
Limited partners’ interest in net income (loss)  $158,773   $(9,297)  $99,054   $(15,908)
                     
Earnings per limited partner unit (basic and diluted)  $3.25   $(0.19)  $2.03   $(0.33)
                     
Weighted average limited partner units outstanding (basic and diluted)   48,871    48,572    48,833    48,555 

 

As of June 30, 2015, there are no unearned performance units outstanding. Unearned performance units totaling 0.2 million units were not included in the computation of diluted net income (loss) per limited partner unit for the three months and six months ended June 30, 2014 because the effect would have been anti–dilutive.

 

NOTE 12. RELATED PARTY TRANSACTIONS

 

Pursuant to an omnibus agreement, we paid EnerVest $3.3 million and $3.0 million in the three months ended June 30, 2015 and 2014, respectively, and $6.6 million and $6.0 million in the six months ended June 30, 2015 and 2014, 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 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 $3.7 million and $3.8 million in the three months ended June 30, 2015 and 2014, respectively, and $7.8 million and $8.3 million in the six months ended June 30, 2015 and 2014, 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:

 

   Six Months Ended 
   June 30, 
   2015   2014 
         
Supplemental cash flows information - cash paid for interest, net of capitalized interest of $4,322 at June 30, 2014  $26,460   $22,781 
           
Cash (refunded) paid for income taxes  $(155)  $155 

 

   As of June 30, 
   2015   2014 
         
Noncash transaction - costs for additions to oil and natural gas properties in accounts payable and accrued liabilities  $9,970   $17,700 

 

Accounts payable and accrued liabilities consisted of the following:

 

   June 30,   December 31, 
   2015   2014 
Costs for additions to oil and natural gas properties  $9,970   $18,028 
Lease operating expenses   8,759    9,701 
Interest   8,333    8,649 
Production and ad valorem taxes   4,334    5,683 
General and administrative expenses   1,883    2,317 
Current portion of ARO   1,940    1,941 
Derivative settlements   268    280 
Other   1,703    1,279 
Total  $37,190   $47,878 

 

NOTE 14. NEW ACCOUNTING STANDARDS

 

In April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015–03, Interest – Imputation of Interest. This ASU changes the presentation of debt issuance costs in financial statements. Under ASU 2015–03, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. The provisions of ASU 2015–03 are applicable to annual reporting periods beginning after December 15, 2015 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.

 

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EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

 

In April 2015, the FASB issued ASU No. 2015–06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015–06 specifies that for purposes of calculating historical earnings per unit under the two class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In addition, qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two class method are also required. The provisions of ASU 2015–06 are applicable to annual reporting periods beginning after December 15, 2015 and interim periods within those annual periods. We will adopt this ASU should we enter into a dropdown transaction.

 

No other new accounting pronouncements issued or effective during the six months ended June 30, 2015 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, 2014.

 

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.

 

With the sale of our interest in Cardinal in October 2014 and the sale of our interest in UEO in June 2015, we no longer operate in the midstream segment. We now 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, 2014, our oil and natural gas properties were 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, the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), and the Permian Basin. As of December 31, 2014, we had estimated net proved reserves of 11.9 MMBbls of oil, 712.2 Bcf of natural gas and 36.1 MMBbls of natural gas liquids, or 1,000.5 Bcfe, and a standardized measure of $1,093.3 million.

 

CURRENT DEVELOPMENTS

 

In the six months ended June 30, 2015, prices for oil, natural gas and natural gas liquids have declined, and they continue to remain low by historical standards. These low prices have affected our business in numerous ways, including:

 

·a material reduction in our revenues and cash flows;

 

·a decrease in proved reserves and possible additional impairments of our oil and natural gas properties as a result of reduced capital spending and the possibility that some of our developed wells and undeveloped wells may become uneconomic;

 

·an increase in our cost of capital and difficulty in accessing capital, including a decrease in the borrowing base under our credit facility; and

 

·an increase in the possibility that some of the purchasers of our oil and natural gas production, or some of the companies that provide us with services, may experience financial difficulties.

 

In response to continued lower prices, we have taken a number of actions to preserve our liquidity and financial flexibility, including:

  

·amending our credit facility in February 2015 to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to EBITDAX covenant to March 31, 2016;

 

·divesting our 21% interest in UEO in June 2015 for net proceeds of $572.2 million and using these net proceeds to repay amounts outstanding under our credit facility and to fund future activities, including acquisitions of oil and natural gas properties;

 

·using the $33.8 million of proceeds from the sale of certain oil and natural gas properties that we deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code that were returned to us in April 2015 to repay amounts outstanding under our credit facility;

 

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·reducing the amount of capital spending we expect to dedicate to the development of our proved undeveloped reserves by approximately 40% in 2015; and

 

·actively seeking alternative sources of capital to develop our proved undeveloped and probable reserves, including farmouts, production payments and joint ventures.

 

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

 

·the level of our operating and administrative costs.

 

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 prices have continued to remain low through June 2015; prices for oil have remained at or below $62 per Bbl and natural gas prices have remained below $3.25 per MmBtu.

 

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 in recent months 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 recent months.

 

In order to mitigate the impact of these 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. Although we have entered into derivative contracts covering a portion of our future production through December 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future. 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.

 

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Utica Shale

 

We hold approximately 173,000 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. 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. In June 2015, we recognized a $47.9 million impairment charge related to a change in our development plans for acreage in the Utica Shale.

 

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 June 2015, 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.

 

RESULTS OF OPERATIONS

 

   Three Months Ended   Six Months Ended 
   June 30,   June 30, 
   2015   2014   2015   2014 
Production data:                    
Oil (MBbls)   237    255    478    520 
Natural gas liquids (MBbls)   563    571    1,145    1,121 
Natural gas (MMcf)   10,018    10,962    20,606    21,798 
Net production (MMcfe)   14,818    15,920    30,344    31,645 
Average sales price per unit:                    
Oil (Bbl)  $52.84   $98.84   $48.39   $96.48 
Natural gas liquids (Bbl)   15.09    30.36    15.10    31.89 
Natural gas (Mcf)   2.27    4.16    2.41    4.42 
Mcfe   2.95    5.54    2.97    5.76 
Average unit cost per Mcfe:                    
Production costs:                    
Lease operating expenses  $1.61   $1.64   $1.56   $1.63 
Production taxes   0.11    0.19    0.11    0.20 
Total   1.72    1.83    1.67    1.83 
Depreciation, depletion and amortization   1.71    1.57    1.69    1.62 
General and administrative expenses   0.54    0.80    0.68    0.79 

 

Three Months Ended June 30, 2015 Compared with the Three Months Ended June 30, 2014

 

Net income (loss) for the three months ended June 30, 2015 was $164.1 million compared with $(9.0) million for the three months ended June 30, 2014. The significant factors in this change were (i) a $247.2 million increase in income from discontinued operations; (ii) an $8.6 million favorable change in (loss) gain on derivatives, net; (iii) a $4.8 million decrease in general and administrative expenses; offset by (iv) a $47.2 million increase in impairment of oil and natural gas properties and (v) a $44.4 million decrease in oil, natural gas and natural gas liquids revenues.

 

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2015 totaled $43.7 million, a decrease of $44.4 million compared with the three months ended June 30, 2014. This was the result of decreases of $41.2 million related to lower prices for oil, natural gas and natural gas liquids and $3.2 million related to decreased oil, natural gas and natural gas liquids production.

 

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Lease operating expenses for the three months ended June 30, 2015 decreased $2.2 million compared with the three months ended June 30, 2014 as the result of $1.8 million from a lower unit cost per Mcfe and $0.4 million related to our decreased production. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.61 in the three months ended June 30, 2015 compared with $1.64 in the three months ended June 30, 2014.

 

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended June 30, 2015 decreased $1.4 million compared with the three months ended June 30, 2014 due to decreased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended June 30, 2015 were $0.11 per Mcfe compared with $0.19 per Mcfe for the three months ended June 30, 2014.

 

Depreciation, depletion and amortization (“DD&A”) for the three months ended June 30, 2015 increased $0.3 million compared with the three months ended June 30, 2014 due to an increase of $2.2 million from a higher DD&A rate offset by $1.9 million from lower production. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for the three months ended June 30, 2015 was $1.71 per Mcfe compared with $1.57 per Mcfe for the three months ended June 30, 2014.

 

 General and administrative expenses for the three months ended June 30, 2015 totaled $7.9 million, a decrease of $4.8 million compared with the three months ended June 30, 2014. This decrease is the result of $3.2 million of costs incurred in the three months ended June 30, 2014 related to the departure of a former officer and $1.7 million of lower equity compensation costs offset by $0.3 million of higher fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.54 per Mcfe in the three months ended June 30, 2015 compared with $0.80 per Mcfe in the three months ended June 30, 2014.

 

In the three months ended June 30, 2015, we incurred leasehold impairment charges of $48.3 million, of which $47.9 million related to a change in our development plans for acreage in the Utica Shale. In the three months ended June 30, 2014, we incurred leasehold impairment charges of $1.1 million.

 

(Loss) gain on derivatives, net was $(9.2) million for the three months ended June 30, 2015 compared with $(17.8) million for the three months ended June 30, 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June 30, 2015 for oil averaged $61.99 per Bbl compared with $53.30 at March 31, 2015, and the 12 month forward prices at June 30, 2015 for natural gas averaged $3.13 per MmBtu compared with $2.91 at March 31, 2015. The 12 month forward price at June 30, 2014 for oil averaged $97.49 per Bbl compared with $97.33 per Bbl at March 31, 2014, and the 12 month forward price at June 30, 2014 for natural gas averaged $4.07 per MmBtu compared with $4.50 at March 31, 2014.

 

Interest expense for the three months ended June 30, 2015 increased $0.7 million compared with the three months ended June 30, 2014 due to $1.1 million from a higher weighted effective average interest rate and $2.4 million from a decrease in capitalized interest offset by $2.8 million from a lower weighted average long–term debt balance.

 

Income from discontinued operations for the three months ended June 30, 2015 increased $247.2 million compared with the three months ended June 30, 2014. The significant factor in the increase was the $246.7 million gain recognized on the sale of our interest in UEO.

 

Six Months Ended June 30, 2015 Compared with the Six Months Ended June 30, 2014

 

Net income (loss) for the six months ended June 30, 2015 was $102.4 million compared with $(15.3) million for the six months ended June 30, 2014. The significant factors in this change were (i) a $250.6 million increase in income from discontinued operations and (ii) a $55.2 million favorable change in (loss) gain on derivatives, net; offset by (iii) a $105.1 million increase in impairment of oil and natural gas properties and (iv) a $92.1 million decrease in oil, natural gas and natural gas liquids revenues.

 

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2015 totaled $90.1 million, a decrease of $92.1 million compared with the six months ended June 30, 2014. This was the result of decreases of $87.5 million related to lower prices for oil, natural gas and natural gas liquids and $4.9 million related to decreased oil and natural gas production offset by an increase $0.3 million from higher natural gas liquids production.

 

Lease operating expenses for the six months ended June 30, 2015 decreased $4.1 million compared with the six months ended June 30, 2014 as the result of $2.0 million from a lower unit cost per Mcfe and $2.1 million related to our decreased production. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.56 in the six months ended June 30, 2015 compared with $1.63 in the six months ended June 30, 2014.

 

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Production taxes for the six months ended June 30, 2015 decreased $3.1 million compared with the six months ended June 30, 2014 due to lower oil, natural gas and natural gas liquids revenues. Production taxes for the six months ended June 30, 2015 were $0.11 per Mcfe compared with $0.20 per Mcfe for the six months ended June 30, 2014.

 

DD&A for the six months ended June 30, 2015 was flat compared with the six months ended June 30, 2014 due to $2.2 million from lower production offset by $2.2 million from a higher average DD&A rate per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for the six months ended June 30, 2015 was $1.69 per Mcfe compared with $1.62 per Mcfe for the six months ended June 30, 2014.

 

General and administrative expenses for the six months ended June 30, 2015 totaled $20.4 million, a decrease of $4.7 million compared with the six months ended June 30, 2014. This decrease is primarily the result of (i) $3.6 million of lower equity compensation costs; (ii) $0.9 million of decreased compensation costs related to the vesting of our phantom units issued under our equity based compensation plan; and (iii) $0.7 million of costs incurred in the six months ended June 30, 2014 related to the departure of a former officer; offset by $0.5 million of higher fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.68 per Mcfe in the six months ended June 30, 2015 compared with $0.79 per Mcfe in the six months ended June 30, 2014.

 

In the six months ended June 30, 2015, we incurred impairment charges of $106.5 million. Of this amount, $58.2 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 riskadjusted discount rates and other relevant data. The remainder of the impairment charges consisted of $48.3 million of leasehold impairments, of which $47.9 million related to a change in our development plans for acreage in the Utica Shale. In the six months ended June 30, 2014, we incurred impairment charges of $1.3 million, of which $0.2 million related to a charge to write down assets held for sale to their fair value and $1.1 million related to leasehold impairment charges.

 

(Loss) gain on derivatives, net was $14.4 million for the six months ended June 30, 2015 compared with $(40.8) million for the six months ended June 30, 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June 30, 2015 for oil averaged $61.99 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at June 30, 2015 for natural gas averaged $3.13 per MmBtu compared with $3.03 at December 31, 2014. The 12 month forward price at June 30, 2014 for oil averaged $97.49 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at June 30, 2014 for natural gas averaged $4.07 per MmBtu compared with $4.19 at December 31, 2013.

 

Interest expense for the six months ended June 30, 2015 increased $2.7 million compared with the six months ended June 30, 2014 due to $0.9 million from a higher weighted effective average interest rate and $4.3 million from a decrease in capitalized interest offset by $2.5 million from a lower weighted average long–term debt balance.

 

Income from discontinued operations for the six months ended June 30, 2015 increased $252.0 million compared with the six months ended June 30, 2014. The significant factor in the increase was the $246.7 million gain recognized on the sale of our interest in 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, contributions to our midstream investments, distributions to our unitholders and general partner and working capital needs. For 2015, 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.

 

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In the six months ended June 30, 2015, prices for oil, natural gas and natural gas liquids have declined, and they continue to remain low by historical standards. In response to these continued lower prices, we have taken a number of actions to preserve our liquidity and financial flexibility, including:

  

·amending our credit facility in February 2015 to include, among other things, an extension of the facility to February 2020, as well as an extension of our senior secured debt to EBITDAX covenant to March 31, 2016;

 

·divesting our 21% interest in UEO for $572.2 million in June 2015 and using the net proceeds to repay all amounts outstanding under our credit facility and to fund future activities, including acquisitions of oil and natural gas properties;

 

·using the $33.8 million of proceeds from the sale of certain oil and natural gas properties that we deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code that were returned to us in April 2015 to repay amounts outstanding under our credit facility;

 

·reducing the amount of capital spending we expect to dedicate to the development of our proved undeveloped reserves by approximately 40% in 2015; and

 

·actively seeking alternative sources of capital to develop our proved undeveloped and probable reserves, including farmouts, production payments and joint ventures.

 

We repaid amounts outstanding under our credit facility with proceeds from the sale of our interest in UEO and the $33.8 million in proceeds from the sale of certain oil and natural gas properties that were deposited with a qualified intermediary. Upon the sale of our interest in UEO, the borrowing base under our credit facility was reduced by $150.0 million to $500.0 million. We plan to invest the remainder of the proceeds from the sale of our interest in UEO in future acquisitions of long–life, producing oil and natural gas properties, which we believe will increase our borrowing base.

 

Long–term Debt

 

As of June 30, 2015, 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 June 30, 2015, the borrowing base was $500.0 million, and we had no amounts outstanding.

 

As of June 30, 2015, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019. As of June 30, 2015, the aggregate carrying amount of the senior notes due 2019 was $499.4 million.

 

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 June 30, 2015, we had $58.8 million of cash and short–term investments, which included $57.6 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with a major financial institution.

 

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 June 30, 2015, all of our counterparties have performed pursuant to their derivative contracts.

 

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Cash Flows

 

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

 

   Six Months Ended 
   June 30, 
   2015   2014 
Operating activities  $73,359   $63,280 
Investing activities   561,880    (123,050)
Financing activities   (584,681)   66,737 

 

Operating Activities

 

Cash flows from operating activities provided $73.4 million and $63.3 million in the six months ended June 30, 2015 and 2014, respectively. The significant factors in the change were a $92.1 million decrease in our oil, natural gas and natural gas liquids revenues and a decrease in working capital, primarily related to lower accounts receivable as a result of lower oil, natural gas and natural gas liquids prices at June 30, 2015 compared with June 30, 2014, offset by $74.0 million of increased cash settlements from our matured derivative contracts. The increased cash settlements are due to the impact of derivative contracts with less favorable terms that expired as of December 31, 2014.

 

Investing Activities

 

During the six months ended June 30, 2015, cash flows used in investing activities from continuing operations totaled $(10.3) million. This consisted of $44.9 million for additions to our oil and natural gas properties 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 $0.8 million in proceeds from the sales 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 UEO.

 

During the six months ended June 30, 2014, cash flows used in investing activities from continuing operations totaled $(39.9) million. This consisted of $44.9 million for additions to our oil and natural gas properties offset by $7.3 million in proceeds from the sales of oil and natural gas properties. Net cash flows used in investing activities from discontinued operations of $83.2 million consisted of increases to our investment in unconsolidated affiliates.

 

Financing Activities

 

During the six months ended June 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 $3.3 million related to the amendment of our credit facility and paid distributions of $50.5 million to holders of our common units, phantom units and our general partner. During the six months ended June 30, 2014, we received $144.0 million from borrowings under our credit facility and paid distributions of $77.4 million to holders of our common units, phantom units and our general partner.

 

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, and our ability to pay distributions;

 

·our business strategy and plans, and future capital expenditures, including plans for the sale of additional acreage in the Utica Shale and the Eagle Ford formation;

 

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

 

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·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;

 

·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;

 

·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, 2014.

 

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 2016. As of June 30, 2015, we have commodity contracts covering approximately 58% of our production attributable to our estimated net proved reserves from July 2015 through December 2016, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Subsequent to June 30, 2015, we entered into additional commodity contracts and now have commodity contracts covering approximately 59% of our production from July 2015 through December 2017. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our commodity contracts at June 30, 2015 was a net asset of $85.6 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 $18.2 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

Interest Rate Risk

 

Our floating rate credit facility also exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in interest rates. If interest rates on our facility increased by 1%, interest expense for the six months ended June 30, 2015 would have increased by approximately $2.4 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 June 30, 2015 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 June 30, 2015 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, 2014.

 

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.

 

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).

 

 25 

 

 

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).

 

+10.1Guarantee, dated as of April 2, 2015, by and among Williams Partners L.P. and CGAS Properties, L.P.

 

+10.2Guarantee, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C.

 

+10.3Membership Interest Purchase Agreement, dated as of April 2, 2015, between CGAS Properties, L.P. and Utica Gas Services, L.L.C.

 

+10.4Amendment No.1 to Membership Interest Purchase Agreement, dated as of May 26, 2015

  

+10.5Membership Interest Purchase Agreement, dated as of May 26, 2015, between CGAS Properties, L.P. and M3 Ohio Gathering LLC

 

+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:  August 7, 2015 By: /s/ NICHOLAS BOBROWSKI
    Nicholas Bobrowski
    Vice President and Chief Financial Officer

 

 27 

 

 

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).

 

+10.1Guarantee, dated as of April 2, 2015, by and among Williams Partners, L.P. and CGAS Properties, L.P.

 

+10.2Guarantee, dated as of April 2, 2015, by and among CGAS Properties, L.P. and Utica Gas Services, L.L.C.

 

+10.3Membership Interest Purchase Agreement, dated as of April 2, 2015, between CGAS Properties, L.P. and Utica Gas Services, L.L.C.

 

+10.4Amendment No.1 to Membership Interest Purchase Agreement, dated as of May 26, 2015

 

+10.5Membership Interest Purchase Agreement, dated as of May 26, 2015, between CGAS Properties, L.P. and M3 Ohio Gathering LLC

 

+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