EV Energy Partners, L.P.
Mar 1, 2017
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EV Energy Partners Announces Fourth Quarter and Full Year 2016 Results, Additional Commodity Hedges, Year-end Proved Reserves and 2017 Guidance

HOUSTON, March 01, 2017 (GLOBE NEWSWIRE) -- EV Energy Partners, L.P. (NASDAQ:EVEP) today announced results for the fourth quarter and full year 2016 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2016 year-end proved reserves and 2017 guidance.

Highlights

Fourth Quarter 2016 Results

For the fourth quarter 2016, EVEP reported a net loss of $165.7 million, or $(3.31) per basic and diluted weighted average limited partner unit outstanding compared to a net loss of $19.2 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding for the third quarter of 2016.  Included in net loss were the following items:

For the fourth quarter of 2015, EVEP reported a net loss of $71.3 million, or $(1.43) per basic and diluted weighted average limited partner unit outstanding.

Production for the fourth quarter of 2016 was 11 Bcf of natural gas, 278 Mbbls of oil and 547 Mbbls of natural gas liquids, or 173.6 million cubic feet equivalent per day (Mmcfe/day). This represents a 17 percent decrease from fourth quarter 2015 production of 209.8 Mmcfe/d and an 11 percent decrease from third quarter 2016 production of 195.3 Mmcfe/day.  The decreases were primarily due to reduced drilling activity and the divestitures completed on December 1, 2016.

Adjusted EBITDAX for the fourth quarter of 2016 was $28.5 million, a 46 percent decrease from the fourth quarter of 2015 and a 10 percent increase over the third quarter of 2016.  Distributable Cash Flow for the fourth quarter of 2016 was $7.9 million, a 70 percent decrease from the fourth quarter of 2015 and a 24 percent increase over the third quarter of 2016.  The decreases in Adjusted EBITDAX and Distributable Cash Flow from the fourth quarter of 2015 were attributable to lower realized hedge gains and lower production, partially offset by higher realized oil, natural gas and natural gas liquids prices.  The increases in Adjusted EBITDAX and Distributable Cash Flow over the third quarter of 2016 were primarily due to higher realized oil, natural gas and natural gas liquids prices and lower operating expenses, partially offset by lower production.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures."

Full Year 2016 Results

For 2016, EVEP reported a net loss of $242.9 million, or $(4.85) per basic and diluted weighted average limited partner unit outstanding as compared to net income of $21.3 million, or $0.41 per basic and diluted weighted average limited partner unit outstanding for 2015.  Included in net loss were the following items:

Production for 2016 was 49.3 Bcf of natural gas, 1.2 Mmbbls of oil and 2.3 Mmbbls of natural gas liquids, or 192.9 Mmcfe/day, which is a 10 percent increase over 2015 production of 174.8 Mmcfe/day.  The increase over 2015 production was primarily due to the addition of producing properties acquired on October 1, 2015.

Adjusted EBITDAX and Distributable Cash Flow for 2016 of $101.3 million and $18.7 million decreased 50 percent and 81 percent, respectively, versus 2015.  The decreases in Adjusted EBITDAX and Distributable Cash Flow as compared to 2015 are primarily due to lower realized hedge gains and lower realized oil and natural gas prices, partially offset by the addition of producing properties acquired on October 1, 2015, lower operating expenses and higher realized natural gas liquids prices. 

"In 2016, our overall results were in line with guidance, we continued to reduce operating costs through the hard work of our asset teams, and we reduced debt by $83 million.  In December, we sold some of our Barnett Shale natural gas assets, and in January, redeployed the proceeds in an oil-weighted Karnes County acquisition that we believe has significantly more drilling opportunities at attractive rates of return in the current commodity price environment.  In 2017, we plan to increase our capital spending, while remaining focused on our cost structure and maintaining sufficient liquidity," said Michael Mercer, President and CEO.

Additional Commodity Hedges

EVEP entered into the following additional commodity hedges in 2016 subsequent to its press release on November 9, 2016.  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
Natural Gas (Mmmbtus)      
Jan - Mar 2018 NYMEX 4,500 $3.46
        
Ethane (Mbbls)      
2017 Mt Belvieu 511.0  $11.66
       
Propane (Mbbls)       
2017 Mt Belvieu 255.5 $25.10

Year-end 2016 Estimated Net Proved Reserves

EVEP's year-end 2016 estimated net proved reserves were 851 Bcfe.  Approximately 68 percent were natural gas, 23 percent were natural gas liquids and 9 percent were crude oil.  In addition, 90 percent were categorized as proved developed.  Year-end 2016 estimated net proved reserves decreased by 22 percent or 246 Bcfe from year-end 2015 estimated net proved reserves due to reduced commodity pricing, asset divestitures, and volumes produced and sold during 2016.  The prices used in determining estimated net proved reserves at December 31, 2016 were $42.75 per Bbl of oil and $2.48 per Mmbtu of natural gas as compared to $50.28 per Bbl of oil and $2.59 per Mmbtu of natural gas at December 31, 2015.

At December 31, 2016, the present value of future net pre-tax cash flows discounted at 10 percent ("PV 10") was $373.6 million (a non-GAAP measure) and the standardized measure of estimated net proved reserves was $371.1 million.  Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the "SEC"), without giving effect to non-property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent.  Our standardized measure includes approximately $2.5 million of present value of future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.  We have included PV 10 because we believe it is a measure frequently utilized by investors.

EVEP's year-end 2016 estimated net proved reserves and standardized measure are net of the recently announced divestiture of 74 Bcf of proved natural gas properties in the Barnett Shale on December 1, 2016 and prior to the acquisition of estimated net proved reserves of 35 Bcfe of Eagle Ford and Austin Chalk oil and natural gas properties in Karnes County, TX which closed on January 31, 2017.

  Estimated Net Proved Reserves
  Crude Oil
(MMBbls)
 Natural
Gas (Bcf)
 NGL's
(MMBbls)
 Natural
Gas
Equivalents
(Bcfe)
 PV 10
($mm)
Barnett Shale 0.4 239.1 21.0 367.8 $128.6 
San Juan Basin 1.1 94.9 7.1 144.0   46.3 
Appalachia Basin 7.2 91.7 0.3 136.4  98.4 
Michigan - 74.7 0.4 77.8  29.1 
Central Texas 2.4 20.5 2.4 49.1  44.0 
Monroe Field -  27.9 - 27.9  (1.2)
Mid-Continent area1.1  18.9 0.4 27.8  18.9 
Permian Basin 0.4 7.6 1.8 20.4  9.5 
Total 12.6 575.3 33.4 851.2  373.6 
           

For comparative purposes, utilizing NYMEX forward closing prices for oil and natural gas on December 30, 2016 (the last trading day of 2016), total NYMEX strip-based proved reserves at December 31, 2016 were 1,277 Bcfe (69 percent proved developed), with a PV 10 of $790 million, an increase of 426 Bcfe over SEC reserves and $416 million over SEC PV 10.  Also at these prices, our January 2017 Karnes County, TX acquisition had strip-based proved reserves of 38 Bcfe (21 percent proved developed), with a PV 10 of $87 million.  NYMEX strip-based proved reserves are calculated based on the SEC proved reserves estimation methodology, but applying NYMEX strip prices rather than SEC prices. We believe that the PV 10 of NYMEX strip-based reserves is useful to investors to illustrate the potential value of proved reserves that are economically recoverable in the current commodity price environment rather than SEC prices. Neither the PV 10 of our SEC reserves, the PV 10 of our NYMEX strip-based reserves nor the standardized measure represents an estimate of fair market value of our oil and natural gas properties.  

2017 Guidance

          
         
         
 ($ in millions)   Full Year 2017
  
 Net Production       
 Natural Gas (Mmcf)   40,720 - 45,005   
 Crude Oil (Mbbls)    1,325 - 1,465   
 Natural Gas Liquids (Mbbls)   2,055 - 2,270   
 Total Mmcfe   61,000 - 67,415   
            
 Average Daily Production (Mmcfe/d)   167  - 185   
           
 Net Transportation Margin (a)  $0.5 -$1.0   
           
 Average Price Differential vs NYMEX         
 Natural Gas ($/Mcf)  ($0.37) -($0.25)   
 Crude Oil ($/Bbl)  ($5.40) -($3.90)   
 NGL (% of NYMEX Crude Oil)   34% -  38%   
           
 Expenses         
 Operating Expenses:         
 LOE and other  $98.1 -$108.5   
 Production Taxes (as % of revenue)   4.2% - 5.2%   
       -   
 General and administrative expense (b)  $22.0 -$26.0   
           
 Capital Expenditures (c)  $30.0 -$45.0   
         
 (a)  Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.
 (b)  Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part, also
 excludes any amounts for future acquisition related due diligence and transaction costs.  
 (c)  Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of
 oil and gas properties.       

Annual Report on Form 10-K and Unitholders' Schedule K-1

EVEP's financial statements and related footnotes are available on our 2016 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website by March 6, 2016 will be unitholders' Schedule K-1's for the tax year 2016.  For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-800-973-7551.

Conference Call

As announced on January 31, 2016, EV Energy Partners, L.P. will host an investor conference call on March 1, 2016, at 9 a.m. Eastern Standard Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-888-245-0988 (quote conference ID 9028703) 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, our reserve quantities and the present value of our reserves, estimates of maintenance capital and production amounts, the information under the heading "2017 Guidance" 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
December 31,
 Twelve Months Ended
December 31,
 
     2016  2015  2016  2015 
 Production data:         
 Oil (Mbbls)  278  351  1,216  1,041 
 Natural gas liquids (Mbbls)  547  655  2,331  2,326 
 Natural gas (Mmcf)  11,029   13,266  49,333  43,592 
  Net production (Mmcfe)  15,975  19,301  70,612  63,792 
 Average sales price per unit: (1)         
 Oil (Bbl) $45.42 $38.69 $38.78 $43.67 
 Natural gas liquids (Bbl)  19.33  13.86  15.32  14.04 
 Natural gas (Mcf)  2.60  1.86  2.02  2.23 
 Mcfe  3.25  2.45  2.59  2.74 
 Average unit cost per Mcfe:          
 Production costs:         
 Lease operating expenses $1.43 $1.54 $1.46 $1.56 
 Production taxes  0.12  0.11  0.10  0.11 
 Total  1.55  1.65  1.56  1.67 
 Depreciation, depletion and amortization  1.73  1.62  1.69  1.66 
 General and administrative expenses  0.55  0.52  0.48  0.62 
            
 (1) Prior to $8.8 million and $44.9 million of net hedge gains on settlements of commodity derivatives for the three months ended December 30, 2016 and 2015, respectively, and $57.9 million and $143.3 million for the twelve months ended December 31, 2016 and 2015, respectively. 


Consolidated Balance Sheets    
(In $ thousands, except number of units)    
     
  December 31, 2016 December 31, 2015
ASSETS    
     
Current assets:    
Cash and cash equivalents $5,557  $20,415 
Accounts receivable:    
Oil, natural gas and natural gas liquids revenues  39,629   24,285 
Related party  745   - 
Other  2,451   7,137 
Derivative asset  201   60,662 
Other current assets  3,718   3,057 
Total current assets  52,301   115,556 
     
Oil and natural gas properties, net of accumulated    
depreciation, depletion and amortization; December 31,    
2016, $1,051,600; December 31, 2015, $971,499  1,497,211   1,790,455 
Other property, net of accumulated depreciation    
and amortization; December 31, 2016, $1,002;    
December 31, 2015, $970  996   1,019 
Restricted cash  52,076   - 
Long-term derivative asset  -   10,741 
Other assets  4,186   5,831 
Total assets $1,606,770  $1,923,602 
     
     
LIABILITIES AND OWNERS' EQUITY    
     
Current liabilities:    
Accounts payable and accrued liabilities:    
Third party $31,700   $43,135 
Related party  5,797   5,952 
Derivative liability  21,679   - 
Income taxes  -   11,657 
Total current liabilities  59,176   60,744 
      
Asset retirement obligations  180,241   174,003 
Long-term debt, net  606,948   688,614 
Long-term derivative liability  955   - 
Other long-term liabilities  1,043   1,682 
     
Commitments and contingencies    
     
Owners' equity:    
Common unitholders - 49,055,214 units and    
48,871,399 units issued and outstanding as of    
December 31, 2016 and 2015, respectively   776,158   1,011,509 
General partner interest  (17,751)   (12,950) 
Total owners' equity   758,407   998,559 
Total liabilities and owners' equity $1,606,770  $1,923,602 
     


Consolidated Statements of Operations         
(In $ thousands, except per unit data)         
          
  Three Months Ended
December 31,

 Twelve Months Ended
December 31,

 
    2016   2015    2016   2015  
Revenues:         
Oil, natural gas and natural gas liquids revenues $51,842  $47,354  $182,696  $175,088  
Transportation and marketing-related revenues  599   598   2,198   2,883  
Total revenues  52,441   47,952    184,894   177,971  
          
Operating costs and expenses:          
Lease operating expenses  22,839   29,793   103,371   99,626  
Cost of purchased natural gas  421   400   1,497   1,988  
Dry hole and exploration costs  (544)   1,975   651   3,695  
Production taxes  1,885    2,076   7,386   6,784  
Accretion expense on obligations  2,079   2,050   8,225   5,598  
Depreciation, depletion and amortization  27,679   31,251   119,171   105,969  
General and administrative expenses  8,775   10,026   33,637   38,994  
Impairment of oil and natural gas properties  127,889   14,423   131,260   136,667  
Impairment of goodwill  -   65,924   -   65,924  
Loss (gain) on settlement of contract  -   1,210   (3,185)   1,210  
Gain on sales of oil and natural gas properties  (69)   (20)   (69)   (551)  
Total operating costs and expenses  190,954   159,108   401,944   465,904  
          
Operating loss  (138,513)   (111,156)   (217,050)   (287,933)  
           
Other income (expense), net:         
Gain (loss) on derivatives, net  (18,758)   26,739   (35,950)   78,145  
Interest expense  (9,933)   (12,057)   (42,487)   (50,336)  
Gain on early extinguishment of debt  -   24,024   47,695    24,024  
Other income, net  936   27   2,522   78  
Total other income (expense), net  (27,755)   38,733   (28,220)   51,911  
          
Income (loss) from continuing operations before income taxes  (166,268)   (72,423)   (245,270)   (236,022)  
Income taxes  596   1,159   2,375   1,843  
Income (loss) from continuing operations  (165,672)   (71,264)    (242,895)   (234,179)  
Income from discontinued operations   -   -   -   255,512  
Net income (loss) $(165,672)  $(71,264)  $(242,895)  $21,333  
          
Earnings per limited partner unit (basic and diluted):          
Income (loss) from continuing operations $(3.31)  $(1.43)  $(4.85)  $(4.72)  
Income from discontinued operations  -   -   -   5.13  
Net income (loss) $(3.31)  $(1.43)  $(4.85)  $0.41  
          
Weighted average limited partner units outstanding (basic and diluted)  49,055   48,871   49,048   48,853  
          
Distributions declared per common unit $     -  $0.075  $     -  $1.575  
          


Consolidated Statements of Cash Flows     
(In $ thousands)     
  Twelve Months Ended
December 31,

 
   2016    2015  
Cash flows from operating activities:     
Net income (loss) $(242,895)  $21,333  
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:     
Income from discontinued operations  -   (255,512)  
Amortization of volumetric production payment liability  (4,108)   (1,196)  
Accretion expense on obligations  8,225   5,598  
Depreciation, depletion and amortization  119,171   105,969  
Equity-based compensation cost  6,611   12,001  
Impairment of oil and natural gas properties  131,260   136,667  
Impairment of goodwill  -   65,924  
Gain on sales of oil and natural gas properties   (69)   (551)  
Loss (gain) on derivatives, net  35,950   (78,145)  
Cash settlements of matured derivative contracts  54,884   140,657  
Gain on early extinguishment of debt  (47,695)    (24,024)  
Deferred taxes  (404)    (13,285)  
Other  2,523   4,487  
Changes in operating assets and liabilities:     
Accounts receivable  (11,403)   14,850  
Other current assets  (361)   511  
Accounts payable and accrued liabilities  (5,862)   (4,067)  
Income taxes   (11,657)   10,683  
Other, net  (295)   (245)  
Net cash flows provided by operating activities from continuing operations  33,875   141,655  
Net cash flows used in operating activities from discontinued operations  -   (372)  
Net cash flows provided by operating activities  33,875   141,283  
       
Cash flows from investing activities:     
Acquisitions of oil and natural gas properties, net of cash acquired  -   (250,357)  
Additions to oil and natural gas properties  (15,258)   (67,923)  
Proceeds from sales of oil and natural gas properties  54,509   1,457  
Restricted cash  (52,076)   33,768  
Cash settlements from acquired derivative contracts  3,003   2,615  
Other  56   73  
Net cash flows used in investing activities from continuing operations  (9,766)   (280,367)  
Net cash flows provided by investing activities from discontinued operations  -   572,160  
Net cash flows (used in) provided by investing activities  (9,766)   291,793  
      
Cash flows from financing activities:     
Long-term debt borrowings  57,000   295,000  
Repayments of long-term debt borrowings   (57,000)   (561,000)  
Redemption of 8% Senior Notes due 2019  (34,978)   (49,954)  
Loan costs paid  (121)   (4,074)  
Contributions from general partner  -   91  
Distributions paid  (3,868)    (100,979)  
Net cash flows used in financing activities   (38,967)   (420,916)  
      
(Decrease) increase in cash and cash equivalents  (14,858)   12,160   
Cash and cash equivalents - beginning of period  20,415   8,255  
Cash and cash equivalents - end of period $5,557  $20,415  
      

Non GAAP Measures

We define Adjusted EBITDAX as net income (loss) plus income from discontinued operations, EBITDAX from discontinued operations, income taxes, interest expense, net, cash settlements of matured interest rate swaps, depreciation, depletion and amortization, accretion expense on obligations, amortization of volumetric production payment (VPP), loss (gain) on derivatives, net, cash settlements of matured derivative contracts, non-cash equity-based compensation, impairment of oil and natural gas properties, impairment of goodwill, non-cash inventory write down expense, dry hole and exploration costs, gain on sales of oil and natural gas properties, loss (gain) on settlement of contract, gain on early extinguishment of debt, and (gain) loss on sale of investment, contained in Other income, net. Distributable Cash Flow is defined as Adjusted EBITDAX less cash income taxes, cash interest expense, net, realized 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 Income (Loss) to Adjusted EBITDAX and Distributable Cash Flow    
(In $ thousands)          
                     
  Three Months Ended
 Twelve Months Ended
  Dec 31, 2016 Dec 31, 2015 Sep 30, 2016 Dec 31, 2016 Dec 31, 2015
           
Net income (loss) $(165,672)  $(71,264)  $(19,230)  $(242,895)  $21,333 
           
Add:          
Income from discontinued operations  -   -   -   -   (255,512) 
EBITDAX from discontinued operations  -   -   -   -   15,941 
Income taxes  (596)   (1,159)   (1,429)   (2,375)   (1,843) 
Interest expense, net  9,932   12,050   9,889   42,476   50,314 
Cash settlements of matured interest rate swaps  -   -   -   -   1,736 
Depreciation, depletion and amortization  27,679   31,251   31,639   119,171   105,969 
Accretion expense on obligations  2,079   2,050   2,057   8,225   5,598 
Amortization of VPP  (1,038)   (1,196)   (1,027)   (4,108)   (1,196) 
Loss (gain) on derivatives, net  18,758   (26,739)   (8,559)   35,950    (78,145) 
Cash settlements of matured derivative contracts  8,765   44,904   10,117   57,887   143,272 
Non-cash equity-based compensation  1,758   2,366   1,889   6,611   12,001 
Impairment of oil and natural gas properties  127,889   14,423   687   131,260   136,667 
Impairment of goodwill  -   65,924   -   -   65,924 
Non-cash inventory write down expense  (422)   973   -   (299)   1,122 
Dry hole and exploration costs  (544)   1,975   294   651   3,695 
Gain on sales of oil and natural gas properties  (69)   (20)   -   (69)   (551) 
Loss (gain) on settlement of contract  -   1,210   -   (3,185)   1,210 
Gain on early extinguishment of debt  -   (24,024)   -   (47,695)   (24,024) 
(Gain) loss on sale of investment, contained in Other income, net  -   -   (309)   (309)   358 
Adjusted EBITDAX $28,519  $52,724   $26,018  $101,296  $203,869 
            
Less:          
Cash income taxes  -    441   (933)   (933)   441 
Cash interest expense, net  9,609   11,264   9,566   39,558   48,504 
Realized losses on interest rate swaps  -   -   -   -   1,736 
Estimated maintenance capital expenditures (1)  11,000   14,875   11,000   44,000   54,672 
Distributable Cash Flow $7,910  $26,144  $6,385  $18,671  $98,516 
           
(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 operating capacity of our other assets over the long term.
 

Total Current Hedge Position

   Swap  Swap
   Collar    Collar    Collar 
PeriodIndex Volume  Price
   Volume    Floor   Ceiling 
Natural Gas (Mmmbtus)      
2017NYMEX32,850$3.07 10,950$2.75$3.27
Jan - Mar 2018NYMEX4,500$3.46    
       
Crude (Mbbls)      
2017WTI365$52.85    
       
Ethane (Mbbls)      
2017Mt Belvieu511.0$11.66    
       
Propane (Mbbls)      
2017Mt Belvieu255.5$25.10    
       
   Notional Amount   Fixed Rate    
Interest Rate Swap Agreements ($ mill)     
Jan 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

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Source: EV Energy Partners, L.P.

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