UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

 

Washington, D.C. 20549

 

FORM 8-K

 

CURRENT REPORT

 

Pursuant to Section 13 or 15(d) of The Securities Exchange Act of 1934

 

Date of Report (Date of earliest event reported):    March 2, 2017 (March 1, 2017)

 

EV Energy Partners, L.P.

(Exact name of registrant as specified in charter)

 

Delaware

(State of Incorporation)

001-33024

(Commission File No.)

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

 

 

 

(former name or former address, if changed since last report)

 

Check the appropriate box below if the Form 8-K filing is intended to simultaneously satisfy the filing obligation of the registrant under any of the following provisions:

 

¨Written communications pursuant to Rule 425 under the Securities Act (17 CFR 230.425)

 

¨Soliciting material pursuant to Rule 14a-12 under the Exchange Act (17 CFR 240.14a-12)

 

¨Pre-commencement communications pursuant to Rule 14d-2(b) under the Exchange Act (17 CFR 240.14d-2(b))

 

¨Pre-commencement communications pursuant to Rule 13e-4(c) under the Exchange Act (17 CFR 240.13e-4(c))

 

 

 

 

Item 7.01 Regulation FD Disclosure.

 

The following information is being furnished pursuant to Item 7.01 “Regulation FD Disclosure.” This information shall not be deemed “filed” for purposes of Section 18 of the Exchange Act or incorporated by reference in any filing under the Securities Act of 1933, as amended, or the Exchange Act, except as shall be expressly set forth by specific reference in such filing.

 

On March 1, 2017, the Partnership issued a press release announcing its fourth quarter and full year 2016 results, additional commodity hedges, year-end proved reserves, and 2017 guidance.  A copy of the press release is attached as Exhibit 99.1 to this Current Report on Form 8-K and is incorporated by reference.

 

Item 9.01 Financial Statements and Exhibits. (Information furnished in this Item 9.01 is furnished pursuant to Item 7.01.)

 

  (d) Exhibits.

 

  99.1 News Release of EV Energy Partners, L.P. dated March 1, 2017

 

 

 

 

 

SIGNATURE

 

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 hereunto duly authorized.

 

  EV Energy Partners, L.P.
     
Dated: March 2, 2017 By: /s/ NICHOLAS BOBROWSKI
    Nicholas Bobrowski  
   

Vice President and Chief Financial Officer of EV

Management LLC, general partner of EV Energy GP, L.P.,

general partner of EV Energy Partners, L.P.  

 

 

 

 

 

 

EXHIBIT INDEX

 

Exhibit No.   Description
     
99.1   News Release of EV Energy Partners, L.P. dated March 1, 2017

 

 

 

 

 

 

Exhibit 99.1

 

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

 

HOUSTON, March 1, 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

 

·Overall operating results for the year in line with 2016 guidance

·Completed divestment of certain gas-weighted assets in the Barnett Shale for $52.1 million on December 1, 2016 (before post-closing purchase price adjustments)

·Completed $58.7 million asset purchase on January 31, 2017 (before post-closing purchase price adjustments) in the Eagle Ford and Austin Chalk in Karnes County, TX using proceeds from the Barnett Shale divestiture through a like-kind exchange transaction and $6.6 million of borrowings under the credit facility

·Repurchased $82.7 million of outstanding Senior Secured Notes due April 2019 for $35 million

·Increased capital spending budget to $30 to $45 million for 2017 from $10.7 million in 2016

·Maintained significant liquidity, which is currently over $175 million, between borrowing base capacity and cash on hand

 

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:

 

·$127.9 million of impairment charges primarily related to the write-down of certain oil and natural gas properties due to the effects of commodity prices on expected future net cash flows and the disposition of oil and natural gas properties,

·$27.5 million of non-cash losses on commodity and interest rate derivatives, and

·$1.8 million of non-cash costs contained in general and administrative expenses.

 

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:

 

·$131.3 million of impairment charges primarily related to the write-down of certain oil and natural gas properties due to the effects of commodity prices on expected future net cash flows and the disposition of oil and natural gas properties,
·$93.8 million of non-cash losses on commodity and interest rate derivatives,
·$47.7 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
·$6.6 million of non-cash costs contained in general and administrative expenses,
·$3.2 of gain on settlement of contract, and
·$0.7 million of dry hole and exploration costs.

 

 

 

 

 

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 area   1.1    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 
Period  Index  Volume   Price   Volume   Floor   Ceiling 
Natural Gas (Mmmbtus)                            
2017  NYMEX   32,850   $3.07    10,950   $2.75   $3.27 
Jan - Mar 2018  NYMEX   4,500   $3.46                
                             
Crude (Mbbls)                            
2017  WTI   365   $52.85                
                             
Ethane (Mbbls)                            
2017  Mt Belvieu   511.0   $11.66                
                             
Propane (Mbbls)                            
2017  Mt Belvieu   255.5   $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