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EX-32.2 - EXHIBIT 32.2 - EV Energy Partners, LPv464150_ex32-2.htm
EX-32.1 - EXHIBIT 32.1 - EV Energy Partners, LPv464150_ex32-1.htm
EX-31.2 - EXHIBIT 31.2 - EV Energy Partners, LPv464150_ex31-2.htm
EX-31.1 - EXHIBIT 31.1 - EV Energy Partners, LPv464150_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 March 31, 2017 

OR 

 

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

 

Commission File Number 

001-33024 

 

EV Energy Partners, L.P. 

(Exact name of registrant as specified in its charter) 

 

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

 

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

 

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

YES þ NO ¨

 

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 ¨   Accelerated filer þ   Non-accelerated filer ¨   Smaller reporting company ¨

 

Emerging growth company ¨

 

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

 

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 May 8, 2017, the registrant had 49,368,869 common units outstanding.

 

 

 

 

 

 

Table of Contents 

 

PART I. FINANCIAL INFORMATION  
     
Item 1. Condensed Consolidated Financial Statements (Unaudited) 2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 16
Item 3. Quantitative and Qualitative Disclosures About Market Risk 22
Item 4. Controls and Procedures 23
     
PART II. OTHER INFORMATION  
     
Item 1. Legal Proceedings 23
Item 1A. Risk Factors 23
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 24
Item 3. Defaults Upon Senior Securities 24
Item 4. Mine Safety Disclosures 24
Item 5. Other Information 24
Item 6. Exhibits 24
     
Signatures   26

 

 1 

 

 

PART I. FINANCIAL INFORMATION 

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

EV Energy Partners, L.P. 

Condensed Consolidated Balance Sheets 

(In thousands, except number of units) 

(Unaudited) 

 

   March 31,   December 31, 
   2017   2016 
ASSETS          
Current assets:          
Cash and cash equivalents  $8,785   $5,557 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   47,125    39,629 
Related party   1,219    745 
Other   2,194    2,451 
Derivative asset   100    201 
Other current assets   3,782    3,718 
Total current assets   63,205    52,301 
           
          
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; March 31, 2017, $1,128,064; December 31, 2016, $1,051,600   1,456,144    1,497,211 
Other property, net of accumulated depreciation and amortization;          
March 31, 2017, $1,010; December 31, 2016, $1,002   988    996 
Assets held for sale   25,094    - 
Restricted cash   -    52,076 
Long–term derivative asset   319    - 
Other assets   3,983    4,186 
Total assets  $1,549,733   $1,606,770 
           
LIABILITIES AND OWNERS’ EQUITY          
Current liabilities:          
Accounts payable and accrued liabilities:          
Third party  $40,123   $31,700 
Related party   -    5,797 
Derivative liability   6,107    21,679 
Total current liabilities   46,230    59,176 
           
Asset retirement obligations   157,770    180,241 
Long–term debt, net   612,095    606,948 
Long–term derivative liability   -    955 
Liabilities related to assets held for sale   23,835    - 
Other long–term liabilities   1,042    1,043 
           
Commitments and contingencies (Note 8)          
           
Owners’ equity:          
Common unitholders – 49,368,869 units and 49,055,214 units issued and outstanding as of March 31, 2017 and December 31, 2016, respectively   727,505    776,158 
General partner interest   (18,744)   (17,751)
Total owners’ equity   708,761    758,407 
Total liabilities and owners’ equity  $1,549,733   $1,606,770 

 

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 
   March 31, 
   2017   2016 
Revenues:          
Oil, natural gas and natural gas liquids revenues  $56,319   $37,739 
Transportation and marketing–related revenues   668    511 
Total revenues   56,987    38,250 
           
Operating costs and expenses:          
Lease operating expenses   23,939    28,915 
Cost of purchased natural gas   480    336 
Dry hole and exploration costs   (20)   130 
Production taxes   2,759    1,671 
Accretion expense on obligations   1,999    2,040 
Depreciation, depletion and amortization   26,980    28,205 
General and administrative expenses   6,696    8,378 
Impairment of oil and natural gas properties   49,587    687 
Gain on settlement of contract   -    (3,185)
Gain on sales of oil and natural gas properties   (26)   - 
Total operating costs and expenses   112,394    67,177 
           
Operating loss   (55,407)   (28,927)
           
Other income (expense), net:          
Gain on derivatives, net   14,229    9,834 
Interest expense   (9,974)   (10,821)
Other income, net   358    755 
Total other income (expense), net   4,613    (232)
           
Loss before income taxes   (50,794)   (29,159)
           
Income taxes   (37)   159 
           
Net loss  $(50,831)  $(29,000)
           
Basic and diluted earnings per limited partner unit:          
Net loss  $(1.01)  $(0.58)
           
Weighted average limited partner units outstanding (basic and diluted)   49,320    49,027 

 

 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, 2016  $776,158   $(17,751)  $758,407 
Equity–based compensation   1,161    24    1,185 
Net loss   (49,814)   (1,017)   (50,831)
Balance, March 31, 2017  $727,505   $(18,744)  $708,761 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 4 

 

 

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Cash Flows 

(In thousands) 

(Unaudited) 

 

   Three Months Ended 
   March 31, 
   2017   2016 
Cash flows from operating activities:          
Net loss  $(50,831)  $(29,000)
Adjustments to reconcile net loss to net cash flows provided by operating activities:          
Amortization of volumetric production payment liability   -    (1,020)
Accretion expense on obligations   1,999    2,040 
Depreciation, depletion and amortization   26,980    28,205 
Equity–based compensation cost   1,185    1,600 
Impairment of oil and natural gas properties   49,587    687 
Gain on derivatives, net   (14,229)   (9,834)
Cash settlements of matured derivative contracts   (2,517)   18,350 
Other   292    413 
Changes in operating assets and liabilities:          
Accounts receivable   (5,437)   10,909 
Other current assets   (64)   (178)
Accounts payable and accrued liabilities   (1,464)   3,520 
Income taxes   -    (11,318)
Other, net   29    (138)
Net cash flows provided by operating activities   5,530    14,236 
           
Cash flows from investing activities:          
Acquisition of oil and natural gas properties   (58,651)   - 
Additions to oil and natural gas properties   (730)   (7,828)
Proceeds from sale of oil and natural gas properties   -    2,420 
Cash settlements from acquired derivative contracts   -    1,475 
Restricted cash   52,076    - 
Other   3    18 
Net cash flows used in investing activities   (7,302)   (3,915)
           
Cash flows from financing activities:          
Repayment of long-term debt borrowings   (5,000)   (28,000)
Long–term debt borrowings   10,000    5,000 
Distributions paid   -    (3,868)
Net cash flows provided by (used in) financing activities   5,000    (26,868)
           
Increase (decrease) in cash and cash equivalents   3,228    (16,547)
Cash and cash equivalents – beginning of year   5,557    20,415 
Cash and cash equivalents – end of period  $8,785   $3,868 

 

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. 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 audited consolidated financial statements and the related notes included in our Annual Report on Form 10–K for the year ended December 31, 2016. 

 

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.

 

Liquidity

 

Our unaudited condensed consolidated financial statements for the quarter ended March 31, 2017 have been prepared assuming that we will continue as a going concern. As discussed in Note 7, at the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not have sufficient liquidity to repay amounts due under the credit agreement and Senior Notes.

 

Management is pursuing options to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. Among the options being considered are (i) working with our bank syndicate to amend our credit agreement, (ii) seeking additional sources of capital, (iii) divesting or acquiring assets, (iv) redeeming or retiring additional amounts of Senior Notes, and (v) reducing operating costs. However, there can be no assurance that these options can be implemented. Absent the implementation of actions that bring us into compliance with the covenants of our credit agreement or a meaningful increase in commodity prices, this raises substantial doubt about our ability to continue as a going concern within one year from the date these unaudited condensed consolidated financial statements are issued. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

 

New Accounting Standards

 

In March 2016, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2016–09, Compensation – Stock Compensation (“ASU 2016-09”). 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. We adopted ASU 2016–09 on January 1, 2017. The adoption of this ASU did not have a material impact on our unaudited condensed consolidated financial statements. See Note 2 for further information.

 

 6 

 

 

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The main objective of ASU 2017-01 is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments of this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments of this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (ii) remove the evaluation of whether a market participant could replace missing elements. For public entities, ASU 2017-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.

 

No other new accounting pronouncements issued or effective during the three months ended March 31, 2017 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements other than those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.

 

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 may 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 currently consist of phantom units. 

 

We estimated the fair value of the phantom units using the Black–Scholes option pricing model. These phantom units are subject to graded vesting over a four year period. Historically, compensation cost has been recognized for these phantom units on a straight–line basis over the service period, net of estimated forfeitures. As of January 1, 2017, we made an accounting policy election to account for forfeitures as they occur, and compensation cost is now recognized for these phantom units on a straight-line basis over the service period with no adjustment for estimated forfeitures. As a result of this election, we recognized a cumulative adjustment to beginning retained earnings of $1.0 million during the three months ended March 31, 2017. Because the phantom units are equity awards, this cumulative adjustment was fully offset within owners’ equity.

 

We recognized compensation cost related to these phantom units of $1.2 million and $1.6 million in the three months ended March 31, 2017 and 2016, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

 

As of March 31, 2017, there was $7.8 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.3 years.

 

NOTE 3. ACQUISITIONS AND DIVESTITURES

 

On January 31, 2017, we acquired a 5.8% working interest in oil and gas properties in Karnes County, Texas for $58.7 million (net of post-closing purchase price adjustments) with $52.1 million of proceeds from the divestiture of our Barnett Shale natural gas properties in December 2016 and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties. The purchase price of $58.7 million was primarily allocated to proved oil and natural gas properties, and this acquisition has an immaterial impact to our pro-forma financial statements. The purchase price allocations for this acquisition are preliminary.

 

In February 2017, we, along with certain institutional partnerships managed by EnerVest, entered into an Agreement of Sale and Purchase to sell certain oil and gas properties in Ohio and Pennsylvania to a third party. The transaction closed on April 10, 2017, and we received net proceeds of $1.3 million. We do not expect to record a gain or loss on this sale. As of March 31, 2017, we had $25.1 million of oil and natural gas properties classified as assets held for sale and $23.8 million of asset retirement obligations classified as liabilities related to assets held for sale in our unaudited condensed consolidated balance sheets.

 

 7 

 

 

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 on derivatives, net” in our unaudited condensed consolidated statements of operations. 

 

As of March 31, 2017, 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 – April 2017 to December 2017   275.0   $52.85   $-   $- 
                     
Natural Gas (MmmBtus):                    
Swaps – April 2017 to December 2017   24,750.0    3.07    -    - 
Swaps – January 2018 to March 2018   4,500.0    3.46    -    - 
Collars – April 2017 to December 2017   8,250.0    -    2.75    3.27 
                     
Natural Gas Liquids (MBbls):                    
Swaps – April 2017 to December 2017   577.5    16.14    -    - 

 

 As of March 31, 2017, we had entered into interest rate swaps with the following terms: 

 

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

 

 8 

 

 

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 March 31, 2017:               
Derivative asset  $639   $(539)  $100 
Long–term derivative asset   319    -    319 
Total  $958   $(539)  $419 
                
As of December 31, 2016:               
Derivative asset  $201   $-   $201 
Long–term derivative asset   -    -    - 
Total  $201   $-   $201 

 

           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 March 31, 2017:               
Derivative liability  $6,646   $(539)  $6,107 
Long–term derivative liability   -    -    - 
Total  $6,646   $(539)  $6,107 
                
As of December 31, 2016:               
Derivative liability  $21,679   $-   $21,679 
Long–term derivative liability   955    -    955 
Total  $22,634   $-   $22,634 

 

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 March 31, 2017 and December 31, 2016, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

 

 9 

 

 

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.

 

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   Significant     
       Markets for   Other   Significant 
       Identical   Observable   Unobservable 
       Assets   Inputs   Inputs 
   Fair Value   (Level 1)   (Level 2)   (Level 3) 
As of March 31, 2017:                    
Assets:                    
Oil, natural gas and natural gas liquids derivatives  $-   $-   $-   $- 
Interest rate swaps   419    -    419    - 
   $419   $-   $419   $- 
                     
Liabilities:                    
Oil, natural gas and natural gas liquids derivatives  $6,018   $-   $6,018   $- 
Interest rate swaps   89    -    89    - 
   $6,107   $-   $6,107   $- 
                     
As of December 31, 2016:                    
Assets:                    
Oil, natural gas and natural gas liquids derivatives  $-   $-   $-   $- 
Interest rate swaps   201    -    201    - 
   $201   $-   $201   $- 
                     
Liabilities:                    
Oil, natural gas and natural gas liquids derivatives  $22,588   $-   $22,588   $- 
Interest rate swaps   46    -    46    - 
   $22,634   $-   $22,634   $- 

 

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. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts to reflect counterparty credit quality and/or the effect of our own creditworthiness. Theses assumed credit risk adjustments are based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation techniques or related inputs in the three months ended March 31, 2017. 

 

 10 

 

 

Nonrecurring Basis

 

During the three months ended March 31, 2017, we recognized $49.5 million of impairment expense related to oil and natural gas properties located in the Mid-Continent area and the Permian Basin. During the three months ended March 31, 2016, we did not incur any impairment charges for any of our oil and natural gas properties.

 

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.

 

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 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 April 2019 was $269.5 million and $242.6 million at March 31, 2017 and December 31, 2016, respectively, which differs from the carrying value of $342.1 million and $341.9 million at March 31, 2017 and December 31, 2016, respectively. The fair value of the senior notes due April 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: 

 

   2017   2016 
Balance as of January 1  $183,476   $176,933 
Liabilities incurred   118    285 
Revisions   -    82 
Accretion expense   1,999    1,988 
Settlements and divestitures   (1,639)   (1,384)
Liabilities held for sale   (23,835)   - 
Balance as of March 31  $160,119   $177,904 

 

As of March 31, 2017 and December 31, 2016, $2.4 million and $3.2 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

 

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NOTE 7. LONG–TERM DEBT 

 

Long–term debt, net consisted of the following:

 

   March 31,   December 31, 
   2017   2016 
         
Credit facility  $270,000   $265,000 
8.0% senior notes due April 2019:          
  Principal outstanding   343,348    343,348 
  Unamortized discount and debt issuance costs (1)   (2,642)   (2,946)
  Unaccreted premium (2)   1,389    1,546 
    342,095    341,948 
Total  $612,095   $606,948 

_____________

(1)Imputed interest rate of 8.59% and 8.99% for March 31, 2017 and December 31, 2016, respectively.

 

(2)Imputed interest rate of 7.54% and 7.22% for March 31, 2017 and December 31, 2016, respectively.

 

Credit Facility 

 

As of March 31, 2017, 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. As of March 31, 2017, we have a $0.3 million letter of credit outstanding.

 

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 3.98% and 3.75% at March 31, 2017 and December 31, 2016, 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 March 31, 2017, 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 April 2017, the borrowing base under the facility was decreased to $375.0 million.

 

 The facility requires the maintenance of the following (as defined in the facility):

 

·the senior secured funded debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) ratio covenant to be no greater than (a) for the fiscal quarters ending March 31, 2017 and June 30, 2017, 3.5 to 1.0 and (b) for the fiscal quarter ending September 30, 2017 and December 31, 2017, 4.0 to 1.0;

 

·the total funded debt to EBITDAX ratio covenant to be no greater than (a) for the fiscal quarter 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;

 

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

 

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

 

As of March 31, 2017, we were in compliance with these financial covenants. Should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes.

 

8.0% Senior Notes due April 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 wholly-owned 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.

 

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 March 31, 2017 or December 31, 2016.

 

NOTE 9. OWNERS’ EQUITY 

 

Units Outstanding 

 

At March 31, 2017, owners’ equity consists of 49,368,869 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. 

 

Issuance of Units 

 

In the three months ended March 31, 2017, we issued 0.3 million common units related to the vesting of equity–based awards.

 

Cash Distributions 

 

During 2016, the board of directors of EV Management announced that it had elected to suspend distributions to unitholders for all four quarters of 2016. The board of directors also elected to suspend distributions for the first quarter of 2017.

 

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NOTE 10. EARNINGS PER LIMITED PARTNER UNIT 

 

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

 

   Three Months Ended 
   March 31, 
   2017   2016 
Net loss  $(50,831)  $(29,000)
General partner’s 2% interest in net loss   1,017    580 
Earnings attributable to unvested phantom units   -    - 
Limited partners’ interest in net loss  $(49,814)  $(28,420)
           
Earnings per limited partner unit (basic and diluted)  $(1.01)  $(0.58)
           
Weighted average limited partner units outstanding (basic and diluted)   49,320    49,027 

 

NOTE 11. RELATED PARTY TRANSACTIONS 

 

Pursuant to an omnibus agreement, we paid EnerVest $3.5 million and $4.0 million in the three months ended March 31, 2017 and 2016, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.

 

We have entered into operating agreements with EnerVest whereby a wholly owned subsidiary of EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest approximately $4.6 million and $6.1 million in the three months ended March 31, 2017 and 2016, 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.

 

As of March 31, 2017, EnerVest Operating owed us $0.5 million and partnerships managed by EnerVest owed us $0.7 million. As of December 31, 2016, we owed EnerVest Operating $5.8 million and partnerships managed by EnerVest owed us $0.7 million.

 

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NOTE 12. OTHER SUPPLEMENTAL INFORMATION

 

Supplemental cash flows and noncash transactions were as follows: 

 

   Three Months Ended 
   March 31, 
   2017   2016 
Supplemental cash flows information:          
Cash paid for interest  $2,603   $1,557 
Cash paid for income taxes, net of refunds   -    11,318 

 

   As of March 31, 
   2017   2016 
         
Non-cash transactions:          
          
Costs for additions to oil and natural gas properties in accounts payable and accrued liabilities  $3,172   $5,420 

 

Accounts payable and accrued liabilities consisted of the following:

 

   March 31,   December 31, 
   2017   2016 
Interest  $12,858   $6,029 
Lease operating expenses   11,719    9,835 
Production and ad valorem taxes   7,316    7,382 
Costs for additions to oil and natural gas properties   3,172    668 
Current portion of ARO   2,350    3,235 
General and administrative expenses   2,145    3,095 
Derivative settlements   12    106 
Other   551    1,350 
Total  $40,123   $31,700 

 

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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, 2016. 

 

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 March 31, 2017, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin. As of December 31, 2016, we had estimated net proved reserves of 12.6 MMBbls of oil, 575.3 Bcf of natural gas and 33.4 MMBbls of natural gas liquids, or 851.2 Bcfe, and a standardized measure of $371.1 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 prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and the beginning of 2017, they have continued to fluctuate.

 

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 remain lower than historical levels and are likely to continue to directionally follow the market for oil.

 

In the three months ended March 31, 2017, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse 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, 2016 were $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, which was significantly lower than forward strip prices. Had we used the forward strip prices at December 31, 2016 through December 31, 2029, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 111% higher and that our reserves on an Mcfe basis would have been approximately 50% higher than our reserves calculated using SEC prices.

 

Our Response to the Current Price Environment

 

Given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:

 

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

 

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·increasing our capital spending budget to $30 - $45 million from $10.7 million in 2016, in an effort to maintain current production levels;

 

·maintaining a sufficient liquidity position to manage through the current environment, which includes continuing to assess the appropriate distribution levels every quarter;

 

·continuing to evaluate strategic acquisitions of long-life, producing oil and natural gas properties such as our Eagle Ford Acquisition in January 2017; 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.

 

During 2016, the board of directors of EV Management elected to suspend distributions to unitholders for all four quarters of 2016. The board of directors also elected to suspend distributions for the first quarter of 2017. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than in previous years. The board of directors will continue to evaluate on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution.

 

As of May 8, 2017, we have $277 million outstanding under our credit facility and $343.3 million of our senior notes due 2019 outstanding, for a total of $620.3 million, and we have over $100 million of liquidity between our borrowing base capacity and cash on hand. Please see Note 1 to our unaudited condensed consolidated financial statements included in “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information regarding our liquidity.

 

Business Environment

 

One of our primary business objectives is to generate sufficient excess cash flow that will allow us to reinstate a stable distribution, which we will grow 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.

 

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. Although we have entered into derivative contracts covering a portion of our future production through March 2018, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices at which 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. An extended period of depressed commodity prices would alter our acquisition and development plans, adversely affect 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 require us to further delay our ability to reinstate our quarterly distribution.

 

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.

 

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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 
   March 31, 
   2017   2016 
Production data:          
Oil (MBbls)   335    317 
Natural gas liquids (MBbls)   512    602 
Natural gas (MMcf)   10,366    12,818 
Net production (MMcfe)   15,447    18,331 
Average sales price per unit:          
Oil (Bbl)  $47.06   $29.12 
Natural gas liquids (Bbl)   20.93    12.22 
Natural gas (Mcf)   2.88    1.65 
Mcfe   3.65    2.06 
Average unit cost per Mcfe:          
Production costs:          
Lease operating expenses  $1.55   $1.58 
Production taxes   0.18    0.09 
Total   1.73    1.67 
Depreciation, depletion and amortization   1.75    1.54 
General and administrative expenses   0.43    0.46 

 

Net loss for the three months ended March 31, 2017 was $50.8 million compared with $29.0 million for the three months ended March 31, 2016. The significant factors in this change were a $48.9 million increase in impairment of oil and gas properties, partially offset by a $18.7 million increase in total revenues, a $4.4 million favorable change in gain on derivatives and a $5.0 million decrease in lease operating expenses.

 

Oil, natural gas and natural gas liquids revenues for the three months ended March 31, 2017 totaled $56.3 million, an increase of $18.6 million compared with the three months ended March 31, 2016. This was the result of an increase of $26.7 million related to higher prices offset by a decrease of $8.1 million primarily related to decreased natural gas and natural gas liquids production. 

 

Lease operating expenses for the three months ended March 31, 2017 decreased $5.0 million compared with the three months ended March 31, 2016 as the result of $4.5 million from decreased production combined with $0.5 million from a lower unit cost per Mcfe. Lease operating expenses were $1.55 per Mcfe in the three months ended March 31, 2017 compared with $1.58 per Mcfe in the three months ended March 31, 2016. 

 

Depreciation, depletion and amortization (“DD&A”) for the three months ended March 31, 2017 decreased $1.2 million compared with the three months ended March 31, 2016 as a result of $5.0 million from decreased production offset by $3.8 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 $1.75 per Mcfe in the three months ended March 31, 2017 compared with $1.54 per Mcfe in the three months ended March 31, 2016. 

 

General and administrative expenses for the three months ended March 31, 2017 totaled $6.7 million, a decrease of $1.7 million compared with the three months ended March 31, 2016. This decrease is primarily the result of $0.7 million of lower equity compensation costs and $0.5 million of lower fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.43 per Mcfe in the three months ended March 31, 2017 compared with $0.46 per Mcfe in the three months ended March 31, 2016. 

 

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In the three months ended March 31, 2017, we incurred proved property impairment of $49.5 million related to oil and natural gas properties located in the Mid-Continent area and the Permian Basin and leasehold impairment charges of $0.1 million. In the three months ended March 31, 2016, we incurred leasehold impairment charges of $0.7 million.

 

Gain on derivatives, net was $14.2 million for the three months ended March 31, 2017 compared with $9.8 million for the three months ended March 31, 2016. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at March 31, 2017 for oil averaged $51.72 per Bbl compared with $56.19 at December 31, 2016, and the 12 month forward prices at March 31, 2017 for natural gas averaged $3.37 per MmBtu compared with $3.61 at December 31, 2016. The 12 month forward price at March 31, 2016 for oil averaged $38.56 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at March 31, 2016 for natural gas averaged $2.19 per MmBtu compared with $2.49 at December 31, 2015.

 

Interest expense for the three months ended March 31, 2017 decreased $0.8 million compared with the three months ended March 31, 2016 due to $1.0 million from a lower weighted average long–term debt balance partially offset by $0.2 million from a higher weighted average effective interest rate.

 

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.

 

In response to continued price volatility, we have taken a number of actions to preserve our liquidity and financial flexibility and, as of May 8, 2017, we have over $100 million of liquidity between our borrowing base capacity and cash on hand. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include those outlined in “—Overview—Our Response to the Current Price Environment.”

 

For 2017, 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 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 March 31, 2017, 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 March 31, 2017, the borrowing base was $450.0 million, and we had $270.0 million outstanding.

 

In April 2017, the borrowing base was decreased to $375.0 million. Although the borrowing base under the credit facility was reduced, we believe we will maintain sufficient liquidity. However, should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our liquidity. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not have sufficient liquidity to repay amounts due under the credit agreement and Senior Notes.

 

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As of March 31, 2017, we have $343.3 million in aggregate principal amount outstanding of our 8.0% senior notes due April 2019. As of March 31, 2017, the aggregate carrying amount of the senior notes due 2019 was $342.1 million.

 

As of May 8, 2017, we have $277 million outstanding under our credit facility and $343.3 million of our senior notes due April 2019 outstanding, for a total of $620.3 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 March 31, 2017, we had $8.8 million of cash and short–term investments, which included $0.7 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

 

Counterparty Exposure

 

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of March 31, 2017, all of our counterparties have performed pursuant to their derivative contracts.

 

Cash Flows

 

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

 

   Three Months Ended 
   March 31, 
   2017   2016 
Operating activities  $5,530   $14,236 
Investing activities   (7,302)   (3,915)
Financing activities   5,000    (26,868)

 

Operating Activities

 

Cash flows from operating activities provided $5.5 million and $14.2 million in the three months ended March 31, 2017 and 2016, respectively. The significant factors in the change were $21.2 million change in working capital, primarily related to higher accounts receivable as a result of higher sales prices during 2017 and $20.9 million of decreased cash settlements from our matured derivative contracts, partially offset by $18.7 million of higher revenues during 2017 and a $11.3 million federal tax payment related to the conversion of an acquired corporation to a single member LLC in 2016.

 

Investing Activities

 

During the three months ended March 31, 2017, we spent $58.7 million for acquisitions of oil and natural gas properties, utilized $52.1 million of restricted cash for those acquisitions, and spent $0.7 million for additions to our oil and natural gas properties. During the three months ended March 31, 2016, we spent $7.8 million for additions to our oil and natural gas properties and received $2.4 million in proceeds from the sale of oil and natural gas properties and $1.5 million in cash settlements from acquired derivative contracts.

 

Financing Activities

 

During the three months ended March 31, 2017, we received $10.0 million from borrowings under our credit facility and repaid $5.0 million of long–term debt borrowings.

 

During the three months ended March 31, 2016, we received $5.0 million from borrowings under our credit facility, repaid $28.0 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.

 

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FORWARD–LOOKING STATEMENTS

 

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

 

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

 

·our business strategy and plans, and future capital expenditures, including plans to optimize the value of our assets;

 

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

 

·market prices;

 

·our future derivative activities;

 

·our ability to meet the financial covenants in our debt agreements; 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;

 

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·governmental regulations;

 

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

 

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

 

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

 

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

 

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

 

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2016 and in “Item 1A. Risk Factors” contained herein.

 

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 March 2018. As of March 31, 2017, we have commodity contracts covering approximately 82% of our estimated production attributable to our net proved reserves from April 2017 through March 2018, 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 March 31, 2017 was a net liability of $6.0 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 $12.2 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

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Interest Rate Risk

 

Our floating rate credit facility and interest rate swaps also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for the three months ended March 31, 2017 would have increased by approximately $0.7 million. The fair value of our interest rate swaps at March 31, 2017 was an asset of $0.3 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $0.2 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

 

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 March 31, 2017 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 March 31, 2017 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

 

Other than the risk factor listed below, 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, 2016.

 

Uncertainty about future commodity prices and our ability to implement the actions described below that will allow us to remain in compliance with all of the restrictive covenants contained in our credit agreement raises substantial doubt about our ability to continue as a going concern.

 

Based on current forward commodity prices, we anticipate that we will be out of compliance with some of the financial covenants and ratios under our credit agreement by the end of the first quarter of 2018, which would cause us to be in default under the credit agreement. If we are unable to obtain a waiver or other suitable relief from the lenders, an Event of Default (as defined in the credit agreement) would result and the lenders could accelerate the outstanding indebtedness, making it immediately due and payable. If the indebtedness under the credit agreement is accelerated, then an Event of Default (as defined by the indenture governing the Senior Notes) under the Company's Senior Notes would occur, which, if it continues beyond any applicable cure periods, would result in the entire principal under the Senior Notes being due and payable immediately. If lenders, and subsequently noteholders, accelerate our outstanding indebtedness (approximately $612 million as of March 31, 2017), such indebtedness will become immediately due and payable, and we will not have sufficient liquidity to repay those amounts.

 

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We are pursuing options to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. Among the options being considered are (i) working with our bank syndicate to amend our credit agreement, (ii) seeking additional sources of capital, (iii) divesting or acquiring assets, (iv) redeeming or retiring additional amounts of Senior Notes, and (v) reducing operating costs. However, there can be no assurance that these options can be implemented. Absent the implementation of actions that bring us into compliance with the covenants of our credit agreement or a meaningful increase in commodity prices, this raises substantial doubt about our ability to continue as a going concern within one year from the date our unaudited condensed consolidated financial statements for the quarter ended March 31, 2017, which do not include any adjustments that might result from the outcome of this uncertainty, are issued. See Note 1 – Organization and Nature of Business to our unaudited condensed consolidated financial statements included in Part I, Item 1of this report.

 

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: 

 

3.1 First 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).
   
3.2 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 Ninth Amendment dated April 1, 2016 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 4, 2016).
   
+31.1 Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.

 

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+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 

 

 25 

 

 

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: May 10, 2017 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 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 Ninth Amendment dated April 1, 2016 to Second Amended and Restated Credit Agreement (incorporated by reference from Exhibit 10.1 to EV Energy Partners, L.P.’s current report on Form 8–K filed with the SEC on April 4, 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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