EV Energy Partners, L.P.
Nov 9, 2017
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EV Energy Partners Announces Third Quarter 2017 Results and Operational Update

HOUSTON, Nov. 09, 2017 (GLOBE NEWSWIRE) -- EV Energy Partners, L.P. (NASDAQ:EVEP) today announced results for the third quarter of 2017 and the filing of its Form 10-Q with the Securities and Exchange Commission.  In addition, EVEP announced its borrowing base was reduced from $375 million to $325 million during its semi-annual borrowing base review.  Further, the Company has provided an update on initial drilling results in multiple areas of focus and added commodity hedges to the portfolio.

Third Quarter 2017 Results

For the third quarter of 2017, EVEP reported a net loss of $17.9 million, or $(0.36) per basic and diluted weighted average limited partner unit outstanding, compared to a net loss of $25.2 million, or $(0.50) per basic and diluted weighted average limited partner unit outstanding, for the second quarter of 2017.  For the third quarter of 2016, EVEP reported a net loss of $19.2 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding.  Included in the 2017 third quarter net loss were the following items:

Production for the third quarter of 2017 was 10.3 Bcf of natural gas, 310 Mbbls of oil and 541 Mbbls of natural gas liquids (NGLs), or 167.1 million cubic feet equivalent per day (Mmcfe/day).  This represents a 14 percent decrease from the third quarter of 2016 production of 195.3 Mmcfe/d and a three percent decrease from the second quarter of 2017 production of 171.9 Mmcfe/day.  The decrease in production from the third quarter of 2016 was primarily due to significantly lower drilling activity in 2016 and the divestiture of producing properties completed on December 1, 2016, partially offset by the addition of Karnes County, TX, producing properties acquired on January 31, 2017.  The decrease in production from the second quarter of 2017 was primarily due to timing on completion of wells in the 2017 drilling program.

Adjusted EBITDAX for the third quarter of 2017 was $17.0 million, a 35 percent decrease from the third quarter of 2016 and a 22 percent decrease from the second quarter of 2017.  EVEP reported Distributable Cash Flow of $(1.1) million for the third quarter of 2017.  The decreases in Adjusted EBITDAX and Distributable Cash Flow from the third quarter of 2016 were primarily attributable to decreased realized hedge gains, decreased natural gas and natural gas liquids production and higher operating expenses, partially offset by higher realized oil, natural gas and natural gas liquids prices.  The decreases in Adjusted EBITDAX and Distributable Cash Flow from the second quarter of 2017 were primarily attributable to lower realized natural gas prices, higher lease operating and cash general and administrative expenses and decreased oil production, partially offset by realized hedge gains.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures."

Credit Facility and Liquidity Update

In October, the borrowing base under the Company's credit facility decreased from $375 million to $325 million.  As of November 7, 2017, EVEP had total debt of $606 million, which included $263 million outstanding under the credit facility and $343 million in outstanding Senior Notes due 2019.  Liquidity from borrowing base capacity and cash on hand is currently over $65 million.  EVEP's next semi-annual borrowing base redetermination is scheduled for April 2018.  For more information regarding EVEP's debt and liquidity, please review EVEP's Quarterly Report on Form 10-Q filed today with the Securities and Exchange Commission.

Operations Update

In September, the Neva #2, an Austin Chalk well in Washington County, Texas, came online with a 24 hour initial production (IP) peak test of 2,529 barrels of oil equivalent per day (boe/d).  The product mix was approximately 29 percent oil, 45 percent NGLs, and 26 percent natural gas.  The well was choked back due to pipeline constraints, but had a 30-day IP of 1,556 boe/d (19 percent oil, 27 percent NGLs, 54 percent natural gas).  EVEP's working interest in the well is approximately 15 percent.  There are three additional Austin Chalk wells included in EVEP's 2017 capital program.  One well has been drilled and completed and is scheduled to begin flowback this week.  Another well has been drilled and is awaiting completion, and the final well is currently being drilled.   EVEP's working interest ranges from 13 to 19 percent.

Additionally, 12 wells began flowback on EVEP's Karnes County, Texas, properties in September.  The average 30-day IP was 1,950 boe/d per well.  The production mix was approximately 84 percent oil, 9 percent natural gas liquids, and 7 percent natural gas.  EVEP expects 13 additional wells to come online before the end of the year.  EVEP's average working interest in these wells is approximately 4.5 percent. 

In the Barnett Shale, nine wells recently began flowback.  EVEP's average working interest in the Barnett wells is approximately 31 percent.

Additional Commodity Hedges

EVEP entered into the following additional commodity hedges in November subsequent to its press release on August 9, 2017.  EVEP's current hedge position, including these new hedges, is presented at the end of this press release under Total Current Hedge Position.

                
    Swap Swap      
Period Index Volume Price      
Crude (MBbls):                
Dec 2017 - Mar 2018 WTI  157.3  $ 57.40         
                 
Propane (MBbls):               
Oct - Dec 2017 Mt Belvieu  55.2  $ 36.91         
Jan - Mar 2018 Mt Belvieu  117.0  $ 36.12         
                

Quarterly Report on Form 10-Q

EVEP's financial statements and related footnotes are available in the third quarter 2017 Form 10-Q, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Conference Call

As announced on October 17, 2017, EV Energy Partners, L.P. will host an investor conference call on November 9, 2017, at 9 a.m. Eastern Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-888-857-6931 (quote conference ID 4841275) at least 5 minutes prior to the start time, or may listen live over the Internet through the Investor Relations section of the EVEP website at http://www.evenergypartners.com

EV Energy Partners, L.P. is a master limited partnership engaged in acquiring, producing and developing oil and natural gas properties.  More information about EVEP is available on the Internet at http://www.evenergypartners.com.

(code #: EVEP/G)

Forward Looking Statements

This press release may include statements that are not historical facts which are "forward-looking statements" within the meaning of the U.S. Private Securities Litigation Reform Act of 1995.  These statements include information about future plans, liquidity, our reserve quantities and the present value of our reserves, estimates of maintenance capital and production amounts, and other statements which include words such as "anticipates," "plans," "projects," "expects," "intends," "believes," "should," and similar expressions of forward-looking information.  Forward-looking statements are inherently uncertain and necessarily involve risks that may affect the business prospects and performance of EVEP. These statements are based on certain assumptions made by EVEP based on its experience and perception of historical trends, current conditions, expected future developments and other factors it believes are appropriate in the circumstances.  Actual results may differ materially from those contained in the press release.  Such risks and uncertainties include, but are not limited to, changes in commodity prices, changes in reserve estimates, requirements and actions of purchasers of properties, exploration and development activities, the availability and cost of financing, the returns on our capital investments and acquisition strategies, the availability of sufficient cash flow to pay distributions and execute our business plan and general economic conditions.  Additional information on risks and uncertainties that could affect our business prospects and performance are provided in the most recent reports of EVEP with the SEC.  You are cautioned not to place undue reliance on these forward-looking statements, which speak only as of the date of this press release. All forward-looking statements included in this press release are expressly qualified in their entirety by the foregoing cautionary statements.

Any forward-looking statement speaks only as of the date on which such statement is made and EVEP undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.


Operating Statistics

             
             
  Three Months Ended Nine Months Ended
  September 30,  September 30,
  2017  2016 2017  2016
Production data:            
Oil (MBbls)   310    308    1,018    938 
Natural gas liquids (MBbls)   541    597    1,581    1,784 
Natural gas (MMcf)   10,263    12,535    30,869    38,304 
Net production (MMcfe)   15,373    17,965    46,460    54,637 
Average sales price per unit: (1)             
Oil (Bbl) $ 45.03  $ 40.40  $ 45.34  $ 36.82 
Natural gas liquids (Bbl)   21.27    14.23    20.15    14.09 
Natural gas (Mcf)   2.59    2.38    2.78     1.86 
Mcfe   3.38    2.82    3.52    2.39 
Average unit cost per Mcfe:            
Production costs:             
Lease operating expenses $ 1.73  $ 1.42  $ 1.65  $ 1.47 
Production taxes   0.17    0.12    0.17    0.10 
Total   1.90    1.54    1.82    1.57 
Depreciation, depletion and amortization   1.41    1.76    1.51    1.67 
General and administrative expenses   0.51     0.47    0.47    0.46 
             

(1) Prior to $0.7 million and $10.1 million of net hedge gains on settlements of commodity derivatives for the three months ended September 30, 2017 and 2016, respectively, and $2.2 million of net hedge losses and $49.1 million of net hedge gains on settlements of commodity derivatives for the nine months ended September 30, 2017 and 2016, respectively.


Condensed Consolidated Balance Sheets
(In $ thousands, except number of units)
(Unaudited)

       
       
  September 30,  December 31,
  2017 2016
ASSETS      
Current assets:      
Cash and cash equivalents $ 13,910  $ 5,557 
Accounts receivable:      
Oil, natural gas and natural gas liquids revenues   42,350    39,629 
Related party   -    745 
Other   1,071    2,451 
Derivative asset   743    201 
Other current assets   4,791    3,718 
Total current assets   62,865    52,301 
       
Oil and natural gas properties, net of accumulated depreciation, depletion and      
amortization; September 30, 2017, $1,162,695; December 31, 2016, $1,051,600    1,411,739    1,497,211 
Other property, net of accumulated depreciation and amortization;      
September 30, 2017, $1,037; December 31, 2016, $1,002   971    996 
Restricted cash   -    52,076 
Long-term derivative assets   193    - 
Other assets   3,577    4,186 
Total assets $ 1,479,345  $ 1,606,770 
       
LIABILITIES AND OWNERS' EQUITY      
Current liabilities:      
Accounts payable and accrued liabilities:       
Third party $ 47,653  $ 31,700 
Related party   4,481    5,797 
Derivative liability   586    21,679 
Total current liabilities    52,720    59,176 
       
Asset retirement obligations    161,371    180,241 
Long-term debt, net   596,397    606,948 
Long-term derivative liability   -    955 
Other long-term liabilities   1,040    1,043 
       
Commitments and contingencies      
       
Owners' equity:      
Common unitholders - 49,368,869 units and 49,055,214 units issued and      
outstanding as of September 30, 2017 and December 31, 2016, respectively   687,380    776,158 
General partner interest   (19,563)    (17,751)
Total owners' equity   667,817    758,407 
Total liabilities and owners' equity $ 1,479,345  $  1,606,770 
 



Condensed Consolidated Statements of Operations
(In $ thousands, except per unit data)
(Unaudited)

             
              
  Three Months Ended Nine Months Ended
  September 30,  September 30,
  2017 2016 2017 2016
Revenues:            
Oil, natural gas and natural gas liquids revenues $ 52,022  $ 50,750  $ 163,745  $ 130,854 
Transportation and marketing-related revenues   629    622     1,945    1,599 
Total revenues   52,651    51,372    165,690    132,453 
             
Operating costs and expenses:            
Lease operating expenses   26,608    25,571    76,782    80,532 
Cost of purchased natural gas    444    435    1,384    1,076 
Dry hole and exploration costs   135    294    190    1,195 
Production taxes   2,573    2,126    7,828    5,501 
Accretion expense on obligations   1,905    2,057     5,774    6,146 
Depreciation, depletion and amortization   21,710    31,639    70,221    91,492 
General and administrative expenses   7,912    8,514     21,631    24,862 
Impairment of oil and natural gas properties   32    687    68,016    3,371 
Gain on settlement of contract   -    -    -     (3,185)
Gain on sales of oil and natural gas properties   (876)   -    (911)   - 
Total operating costs and expenses   60,443    71,323    250,915    210,990 
              
Operating loss   (7,792)   (19,951)   (85,225)   (78,537)
             
Other income (expense), net:            
Gain (loss) on derivatives, net   (152)   8,559    20,588    (17,192)
Interest expense   (10,092)   (9,889)   (30,501)   (32,554)
Gain on early extinguishment of debt   -    -    -    47,695 
Other income, net   68    622    1,149    1,586 
Total other income (expense), net   (10,176)   (708)   (8,764)   (465)
             
Loss before income taxes   (17,968)   (20,659)   (93,989)   (79,002)
             
Income taxes   80    1,429    109    1,779 
             
Net loss $ (17,888) $ (19,230) $ (93,880) $ (77,223)
             
Basic and diluted earnings per limited partner unit:            
Net loss $ (0.36) $ (0.38) $ (1.86) $ (1.54)
             
Weighted average limited partner units outstanding             
(basic and diluted)   49,369    49,055    49,353    49,046 
 



Condensed Consolidated Statements of Cash Flows
(In $ thousands)
(Unaudited)

       
       
  Nine Months Ended
  September 30,
  2017  2016 
Cash flows from operating activities:      
Net loss $ (93,880) $ (77,223)
Adjustments to reconcile net loss to net cash flows provided by operating activities:      
Amortization of volumetric production payment liability   -    (3,070)
Accretion expense on obligations   5,774    6,146 
Depreciation, depletion and amortization   70,221    91,492 
Equity-based compensation cost   3,290    4,853 
Impairment of oil and natural gas properties   68,016    3,371 
Gain on sales of oil and natural gas properties   (911)   - 
(Gain) loss on derivatives, net    (20,588)   17,192 
Cash settlements of matured derivative contracts   (2,196)    46,299 
Gain on early extinguishment of debt   -    (47,695)
Other   820    1,822 
Changes in operating assets and liabilities:      
Accounts receivable   1,681    (8,597)
Other current assets   (649)   (291)
Accounts payable and accrued liabilities   2,993    4,158 
Income taxes   -     (11,657)
Other, net   (235)   (277)
Net cash flows provided by operating activities    34,336    26,523  
       
Cash flows from investing activities:      
Acquisition of oil and natural gas properties   (61,400)   - 
Additions to oil and natural gas properties   (9,344)   (14,266)
Proceeds from sale of oil and natural gas properties   3,639     2,420 
Cash settlements from acquired derivative contracts   -    2,823 
Restricted cash   52,076    - 
Other   46    33 
Net cash flows used in investing activities    (14,983)   (8,990)
       
Cash flows from financing activities:      
Repayment of long-term debt borrowings   (28,000)   (41,000)
Long-term debt borrowings   17,000    48,000 
Redemption of Senior Notes due 2019   -    (34,978)
Loan costs incurred   -    (121)
Distributions paid   -    (3,868)
Net cash flows used in financing activities   (11,000)   (31,967)
       
Increase (decrease) in cash and cash equivalents   8,353    (14,434)
Cash and cash equivalents - beginning of year   5,557    20,415 
Cash and cash equivalents - end of period $ 13,910  $ 5,981 
 



Non­­-GAAP Measures

We define Adjusted EBITDAX as net loss plus income taxes, interest expense, net, depreciation, depletion and amortization, accretion expense on obligations, amortization of volumetric production payment (VPP), (gain) loss on derivatives, net, cash settlements of matured commodity derivative contracts, non-cash equity-based compensation, impairment of oil and natural gas properties, non-cash oil inventory adjustment, dry hole and exploration costs, gain on settlement of contract, gain on early extinguishment of debt, gain on sales of oil and natural gas properties, and other income, net.  Distributable Cash Flow is defined as Adjusted EBITDAX less cash income taxes, cash interest expense, net, realized (gains) losses on interest rate swaps, and estimated maintenance capital expenditures.

Adjusted EBITDAX and Distributable Cash Flow are used by our management to provide additional information and statistics relative to the performance of our business, including (prior to the creation of any reserves) the cash available to pay distributions to our unitholders.  We believe these financial measures may indicate to investors whether or not we are generating cash flow at a level that can sustain or support quarterly distributions.  Adjusted EBITDAX and Distributable Cash Flow are also quantitative standards used throughout the investment community with respect to performance of publicly-traded partnerships.  Adjusted EBITDAX and Distributable Cash Flow should not be considered as alternatives to net income, operating income, cash flows from operating activities or any other measure of financial performance or liquidity presented in accordance with GAAP.  Adjusted EBITDAX and Distributable Cash Flow exclude some, but not all, items that affect net income and operating income and these measures may vary among companies.  Therefore, our Adjusted EBITDAX and Distributable Cash Flow may not be comparable to similarly titled measures of other companies.

Reconciliation of Net Loss to Adjusted EBITDAX and Distributable Cash Flow
(In $ thousands)
(Unaudited)

                
                 
  Three Months Ended Nine Months Ended
  Sep 30, 2017 Sep 30, 2016 Jun 30, 2017 Sep 30, 2017 Sep 30, 2016
                
Net loss $  (17,888) $ (19,230) $ (25,161) $  (93,880) $ (77,223)
                
Add:               
Income taxes   (80)   (1,429)   (66)   (109 )   (1,779)
Interest expense, net   10,092     9,889    10,435    30,501     32,544 
Depreciation, depletion and amortization   21,710    31,639    21,531    70,221    91,492 
Accretion expense on obligations   1,905    2,057    1,870    5,774    6,146 
Amortization of VPP   -    (1,027)   -    -    (3,070)
(Gain) loss on derivatives, net   152    (8,559)   (6,511)   (20,588)   17,192 
Cash settlements of matured commodity               
derivative contracts   684    10,117    (404)   (2,173)   49,122 
Non-cash equity-based compensation   1,086    1,889     1,019    3,290    4,853 
Impairment of oil and natural gas properties   32    687    18,397    68,016    3,371 
Non-cash oil inventory adjustment    -    -    424    424    123 
Dry hole and exploration costs   135    294    75    190    1,195 
Gain on settlement of contract   -    -    -    -    (3,185)
Gain on early extinguishment of debt   -    -    -    -    (47,695)
Gain on sales of oil and natural gas properties   (876)   -    -    (1,108)   - 
Other income, net   -    (309)   (9)   -    (309)
Adjusted EBITDAX   16,952    26,018    21,600    60,558    72,777 
                
Less:               
Cash income taxes   -    (933)   -    -    (933)
Cash interest expense, net   9,633    9,566    9,647    28,780    29,950 
Realized (gains) losses on interest rate swaps   (49)   -    9    23    - 
Estimated maintenance capital expenditures (1)   8,500    11,000    8,500    25,500     33,000 
Distributable Cash Flow $ (1,131) $ 6,385  $ 3,444  $  6,256  $ 10,760 
 

(1) Estimated maintenance capital expenditures are those expenditures estimated to be necessary to maintain the production levels of our oil and gas properties over the long term and the operation capacity of our other assets over the long term.

Total Current Hedge Position

                 
                
    Swap Swap Collar Collar Collar
Period Index Volume Price Volume Floor Ceiling
Natural Gas (MmmBtus):                
Oct - Dec 2017 NYMEX  8,280.0 $ 3.07  2,760.0 $ 2.75 $ 3.27
Jan - Mar 2018 NYMEX  4,500.0 $ 3.46  - $ - $ -
                
Crude (MBbls):               
Oct - Nov 2017 WTI  61.0 $ 52.85  - $ - $ -
Dec 2017 WTI  71.3 $ 55.42  - $ - $ -
Jan - Mar 2018 WTI  117.0 $ 57.40  - $ -  $ -
                
Ethane (MBbls):               
Oct - Dec 2017 Mt Belvieu  128.8 $ 11.66  - $ - $ -
                
Propane (MBbls):               
Oct - Dec 2017 Mt Belvieu  119.6 $ 30.55  - $ - $ -
Jan - Mar 2018 Mt Belvieu  117.0 $ 36.12  - $ - $ -
                


      
      
Period Notional Amount Fixed Rate
Interest Rate Swap Agreements: ($ mil)  
Oct 2017 - Dec 2017 $ 100  1.039%
Jan 2018 - Sep 2020 $ 100 1.795%
       

EV Energy Partners, L.P., Houston
Nicholas Bobrowski
713-651-1144
http://www.evenergypartners.com

Source: EV Energy Partners, L.P.

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