EV Energy Partners Announces Fourth Quarter and Full Year 2015 Results, Year-end Proved Reserves and 2016 Guidance

Feb 29, 2016, 06:37 ET from EV Energy Partners, L.P.

HOUSTON, Feb. 29, 2016 /PRNewswire/ -- EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the fourth quarter and full year 2015 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2015 year-end proved reserves and 2016 guidance.

Fourth Quarter 2015 Results

Adjusted EBITDAX for the fourth quarter of 2015 was $52.7 million, a 5 percent decrease from the fourth quarter of 2014 and a 20 percent increase over the third quarter of 2015.  Distributable Cash Flow for the fourth quarter of 2015 was $26.1 million, a 4 percent increase over the fourth quarter of 2014 and a 30 percent increase over the third quarter of 2015.  The decrease in Adjusted EBITDAX from the fourth quarter of 2014 was primarily attributable to significantly lower realized commodity prices and the sale of midstream interests in the second quarter of 2015 partially offset by increased realized hedge gains on commodity derivatives and the addition of producing properties acquired on October 1, 2015.  The increase in Adjusted EBITDAX over the third quarter 2015 and the increases in distributable cash flow were primarily due to the addition of producing properties acquired on October 1, 2015.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures."

Production for the fourth quarter of 2015 was 13.3 Bcf of natural gas, 351 Mbbls of oil and 655 Mbbls of natural gas liquids, or 209.8 million cubic feet equivalent per day (Mmcfe/day). This represents a 23 percent increase over fourth quarter 2014 production of 170.9 Mmcfe/d and a 36 percent increase over third quarter 2015 production of 153.8 Mmcfe/day.  The increase was primarily due to acquisitions completed on October 1, 2015.

EVEP reported a net loss of $71.3 million, or $(1.43) per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2015. Included in net loss were the following items:

  • $14.4 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,
  • $65.9 million of impairment of goodwill related to properties acquired on October 1,
  • $24.0 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
  • $18.2 million of non-cash losses on commodity and interest rate derivatives,
  • $2.4 million of non-cash costs contained in general and administrative expenses,
  • $2.0 million of dry hole and exploration costs,
  • $1.2 of loss on settlement of contract, and
  • $0.5 million of cash due diligence and other transaction costs contained in general and administrative expenses for properties acquired on October 1.

For the third quarter of 2015, EVEP reported a net loss of $9.8 million, or $(0.20) per basic and diluted weighted average limited partner unit outstanding.  For the fourth quarter of 2014, EVEP reported net income of $102.4 million, or $2.03 per basic and diluted weighted average limited partner unit outstanding.

Full Year 2015 Results

Adjusted EBITDAX and Distributable Cash Flow for 2015 of $203.9 million and $98.5 million decreased 10 percent and 12 percent, respectively, versus 2014.  The decreases in Adjusted EBITDAX and Distributable Cash Flow as compared to 2014 are primarily due to significantly lower realized commodity prices and the sale of our Utica midstream interests in the second quarter of 2015 partially offset by significantly higher realized hedge gains on commodity derivatives, decreased operating costs and expenses and the addition of producing properties acquired on October 1, 2015. 

Production for 2015 was 43.6 Bcf of natural gas, 1.0 Mbbls of oil and 2.3 Mbbls of natural gas liquids, or 174.8 Mmcfe/day, which is essentially flat compared to 2014 production of 174.1 Mmcfe/day.

For 2015, EVEP reported net income of $21.3 million, or $0.41 per basic and diluted weighted average limited partner unit outstanding.  Included in net income were the following items:

  • $255.5 million in income from discontinued operations, which includes $246.7 million of gain related to the sale of our interest in Utica East Ohio (UEO);
  • $136.7 million of impairment charges related to the write-down of certain oil and natural gas properties primarily due to the effects of commodity prices on expected future net cash flows and due to a change in the development plans for acreage in the Utica Shale,
  • $65.9 million of impairment of goodwill related to properties acquired on October 1,
  • $24.0 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
  • $65.1 million of non-cash gains on commodity and interest rate derivatives,
  • $12.0 million of non-cash costs contained in general and administrative expenses,
  • $3.7 million of dry hole and exploration costs,
  • $1.2 of loss on settlement of contract,
  • $1.0 million of cash due diligence and other transaction costs contained in general and administrative expenses for properties acquired on October 1, and
  • $0.6 million gain on the sales of oil and natural gas properties.

For 2014, EVEP reported net income of $129.7 million, or $2.58 per basic and diluted weighted average limited partner unit outstanding. 

"We are pleased with our results for the fourth quarter, which were in-line with the midpoint of our previously issued guidance.  With this difficult and prolonged downturn, we have significantly reduced our capital budget for 2016 and are continuing to focus on further reducing our operating costs and maintaining financial flexibility and liquidity under our credit facility.  We currently have over $375 million of liquidity and, based on our guidance and current commodity prices, expect to generate free cash flow after interest expense and capital expenditures in 2016," said Michael Mercer, President and CEO.

Year-end 2015 Estimated Net Proved Reserves

EVEP's year-end 2015 estimated net proved reserves were 1,096.7 Bcfe.  Approximately 68 percent were natural gas, 20 percent were natural gas liquids and 12 percent were crude oil.  In addition, 83% percent were categorized as proved developed.  Year-end 2015 estimated net proved reserves increased by 96.3 Bcfe from year-end 2014 estimated net proved reserves.  The year-end 2015 reserve volumes include an increase of 330.5 Bcfe from acquisitions closed in the fourth quarter of 2015 and a reduction of 268.5 Bcfe primarily due to a significantly lower SEC pricing environment compared to year-end 2014.  The prices used in determining estimated net proved reserves at December 31, 2015 were $50.28 per Bbl of oil and $2.59 per Mmbtu of natural gas as compared to $94.99 per Bbl of oil and $4.35 per Mmbtu of natural gas at December 31, 2014.

At December 31, 2015, the present value of future net pre-tax cash flows discounted at 10 percent ("PV 10") was $539.9 million and the standardized measure (a non-GAAP measure) of estimated net proved reserves was $536.4 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%.  Our standardized measure includes approximately $3.5 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.

 


Estimated Net Proved Reserves


Crude Oil (MMBbls)


Natural Gas (Bcf)


NGL's (MMBbls)


Natural Gas Equivalents (Bcfe)

PV 10 ($mm)

Barnett Shale

0.5


356.5


22.9


497.0

$193.6

Appalachia Basin

15.0


106.1


0.6


199.5

143.3

San Juan Basin

1.0


99.7


6.2


143.1

49.4

Michigan

-


84.1


0.6


87.9

38.7

Central Texas

3.5


28.0


3.4


69.1

68.6

Mid-Continent area

1.6


27.6


0.6


40.8

30.9

Monroe Field

-


36.1


-


36.1

0.9

Permian Basin

0.4


8.9


2.0


23.2

14.5


22.0


747.0


36.3


1,096.7

$539.9

 

2015 capital spending of $67.9 million added SEC proved reserves of 100.6 Bcfe, resulting in a cost of $0.67 per Mcfe and reserve replacement of 158 percent.

 


2016 Guidance


($ in millions)


Full Year 2016


Net Production






Natural Gas (Mmcf)


47,670

-

52,685


Crude Oil (Mbbls)


1,220

-

1,345


Natural Gas Liquids (Mbbls)


2,230

-

2,465


Total Mmcfe


68,370

-

75,545








Average Daily Production (Mmcfe/d)


187

-

206








Net Transportation Margin(a)


$0.5

-

$1.0








Average Price Differential vs NYMEX






Natural Gas ($/Mcf)


($0.46)

-

($0.34)


Crude Oil ($/Bbl)


($4.50)

-

($3.00)


NGL (% of NYMEX Crude Oil)


30%


34%








Expenses






Operating Expenses:






LOE and other


$107.9

-

$119.3


Production Taxes (as % of revenue)


4.1%

-

5.1%








General and administrative expense(b)


$24.0

-

$28.0








E&P Capital Expenditures(c)


$10.0

-

$18.0



(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 2015 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 7, 2015 will be unitholders' Schedule K-1's for the tax year 2015.  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 25, 2016, EV Energy Partners, L.P. will host an investor conference call on February 29, 2016, at 9 a.m. Eastern Standard Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-888-437-9445 (quote conference ID 5107524) 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 gas properties.  More information about EVEP is available on the Internet at http://www.evenergypartners.com.

(code #: EVEP/G)

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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 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 EV Energy Partners, L.P. These statements are based on certain assumptions made by EV Energy Partners 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 EV Energy Partners with the Securities and Exchange Commission.  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,



2015


2014


2015


2014

Production data:









Oil (Mbbls)


351


263


1,041


1,052

Natural gas liquids (Mbbls)


655


597


2,326


2,311

Natural gas (Mmcf)


13,266


10,565


43,592


43,363

Net production (Mmcfe)


19,301


15,722


63,792


63,540

Average sales price per unit: (1)









Oil (Bbl)


$ 38.69


$ 69.91


$ 43.67


$ 89.15

Natural gas liquids (Bbl)


13.86


22.54


14.04


28.81

Natural gas (Mcf)


1.86


3.53


2.23


4.02

Mcfe


2.45


4.39


2.74


5.27

Average unit cost per Mcfe:









Production costs:









Lease operating expenses


$ 1.54


$ 1.77


$ 1.56


$ 1.66

Production taxes


0.11


0.16


0.11


0.19

Total


1.65


1.93


1.67


1.85

Depreciation, depletion and amortization


1.62


1.85


1.66


1.67

General and administrative expenses


0.52


0.65


0.62


0.71










(1) Prior to $44.9 million and $14.4 million of net hedge gains on settlements of commodity derivatives for the three months ended December 31, 2015 and December 31, 2014, respectively, and $145.0 million and $8.8 million for the twelve months ended December 31, 2015 and December 31, 2014, respectively.

 

Consolidated Balance Sheets





(In $ thousands, except number of units)












December 31,
2015


December 31,
2014

ASSETS





Current assets:





Cash and cash equivalents


$ 20,415


$ 8,255

Accounts receivable:





Oil, natural gas and natural gas liquids revenues


24,285


32,758

Related party


-


1,043

Other


7,137


4,570

Derivative asset


60,662


113,044

Other current assets


3,057


2,000

Assets held for sale


-


315,173

Total current assets


115,556


476,843






Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; December 31, 2015, $971,499; December 31, 2014, $778,679










1,790,455


1,710,925

Other property, net of accumulated depreciation and amortization; December 31, 2015, $970; December 31, 2014, $898






1,019


1,141

Restricted cash


-


33,768

Long–term derivative asset


10,741


20,647

Other assets


5,831


2,837

Total assets


$ 1,923,602


$ 2,246,161











LIABILITIES AND OWNERS' EQUITY















Current liabilities:





Accounts payable and accrued liabilities:





Third party


$ 43,135


$ 47,878

Related party


5,952


-

Income taxes


11,657


-

Total current liabilities


60,744


47,878






Asset retirement obligations


174,003


103,832

Long–term debt, net


688,614


1,027,349

Other long–term liabilities


1,682


989






Commitments and contingencies










Owners' equity:





Common unitholders - 48,871,399 units and 48,572,019 units issued and outstanding as of December 31, 2015 and 2014, respectively






1,011,509


1,077,826

General partner interest


(12,950)


(11,713)

Total owners' equity


998,559


1,066,113

Total liabilities and owners' equity


$ 1,923,602


$ 2,246,161

 

Consolidated Statements of Operations









(In $ thousands, except per unit data)




















Three Months Ended 
December 31,


Twelve Months Ended
December 31,






2015


2014


2015


2014

Revenues:









Oil, natural gas and natural gas liquids revenues


$ 47,354


$ 69,090


$ 175,088


$ 334,729

Transportation and marketing–related revenues


598


1,085


2,883


4,676

Total revenues


47,952


70,175


177,971


339,405










Operating costs and expenses:









Lease operating expenses


29,793


27,779


99,626


105,781

Cost of purchased natural gas


400


808


1,988


3,533

Dry hole and exploration costs


1,975


783


3,695


6,726

Production taxes


2,076


2,462


6,784


11,976

Accretion expense on obligations


2,050


1,201


5,598


4,835

Depreciation, depletion and amortization


31,251


29,112


105,969


106,073

General and administrative expenses


10,026


10,220


38,994


44,955

Impairment of oil and natural gas properties


14,423


111,701


136,667


113,968

Impairment of goodwill


65,924


-


65,924


-

Loss on settlement of contract


1,210


-


1,210


-

Gain on sales of oil and natural gas properties


(20)


(31,835)


(551)


(33,319)

Total operating costs and expenses


159,108


152,231


465,904


364,528










Operating loss


(111,156)


(82,056)


(287,933)


(25,123)










Other income, net:









Gain on derivatives, net


26,739


102,984


78,145


99,720

Interest expense


(12,057)


(14,385)


(50,336)


(52,578)

Gain on early extinguishment of debt


24,024


-


24,024


-

Other income, net


27


246


78


702

Total other income, net


38,733


88,845


51,911


47,844










(Loss) income from continuing operations before income taxes


(72,423)


6,789


(236,022)


22,721

Income taxes


1,159


(652)


1,843


(476)

(Loss) income from continuing operations


(71,264)


6,137


(234,179)


22,245

Income from discontinued operations


-


96,239


255,512


107,475

Net (loss) income


($ 71,264)


$ 102,376


$ 21,333


$ 129,720










Basic and diluted earnings per limited partner unit:









(Loss) income from continuing operations


($ 1.43)


$ 0.11


($ 4.72)


$ 0.41

Income from discontinued operations


-


$ 1.92


$ 5.13


$ 2.17

Net (loss) income


($ 1.43)


$ 2.03


$ 0.41


$ 2.58










Weighted average limited partner units outstanding (basic and diluted)


48,871


48,572


48,853


48,563










Distributions declared per unit


$ 0.075


$ 0.500


$ 1.575


$ 2.819










 

Consolidated Statements of Cash Flows





(In $ thousands)







Twelve Months Ended
December 31,





2015


2014

Cash flows from operating activities:





Net income


$ 21,333


$ 129,720

Adjustments to reconcile net income to net cash flows provided by operating activities:





Income from discontinued operations


(255,512)


(107,475)

Amortization of volumetric production payment liability


(1,196)


-

Accretion expense on obligations


5,598


4,835

Depreciation, depletion and amortization


105,969


106,073

Equity–based compensation


12,001


19,289

Impairment of oil and natural gas properties


136,667


113,968

Impairment of goodwill


65,924


-

Gain on sales of oil and natural gas properties


(551)


(33,319)

Gain on derivatives, net


(78,145)


(99,720)

Cash settlements of matured derivative contracts


140,657


5,313

Gain on early extinguishment of debt


(24,024)


-

Deferred taxes


(13,285)


-

Other


4,487


5,703

Changes in operating assets and liabilities, net of effects of amounts acquired:





Accounts receivable


14,850


3,275

Other current assets


511


(1,203)

Accounts payable and accrued liabilities


(4,067)


2,368

Income taxes


10,683


-

Other, net


(245)


(627)

Net cash flows provided by operating activities from continuing operations


141,655


148,200

Net cash flows used in operating activities from discontinued operations


(372)


-

Net cash flows provided by operating activities    


141,283


148,200






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 


(67,923)


(102,761)

Prepaid drilling costs


-


(2,501)

Proceeds from sales of oil and natural gas properties


1,457


45,183

Restricted cash


33,768


(33,768)

Cash settlements from acquired derivative contracts


2,615


-

Other


73


48

Net cash flows used in investing activities from continuing operations


(280,367)


(93,799)

Net cash flows provided by investing activities from discontinued operations


572,160


46,985

Net cash flows provided by (used in) investing activities


291,793


(46,814)






Cash flows from financing activities:





Long-term debt borrowings


295,000


209,000

Repayment of long-term debt borrowings


(561,000)


(159,000)

Redemption of 8% Senior Notes due 2019


(49,954)


-

Loan costs paid


(4,074)


-

Contributions from general partner


91


154

Distributions paid


(100,979)


(154,978)

Other


-


(5)

Net cash flows used in financing activities


(420,916)


(104,829)






Increase (decrease) in cash and cash equivalents


12,160


(3,443)

Cash and cash equivalents – beginning of period


8,255


11,698

Cash and cash equivalents – end of period


$ 20,415


$ 8,255






 

Non GAAP Measures

We define Adjusted EBITDAX as net (loss) income 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), 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 on settlement of contract, gain on early extinguishment of debt, and loss on sale of investment in unconsolidated affiliates, 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 an increase in our quarterly distribution rates. 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) Income to Adjusted EBITDAX and Distributable Cash Flow

(In $ thousands)




















Three Months Ended 
December 31,


Twelve Months Ended 
December 31,






2015


2014


2015


2014










Net (loss) income


($ 71,264)


$ 102,376


$ 21,333


$ 129,720










Add:









Income from discontinued operations


-


(96,239)


(255,512)


(107,475)

EBITDAX from discontinued operations


-


7,874


15,941


25,641

Income taxes


(1,159)


652


(1,843)


476

Interest expense, net


12,050


14,385


50,314


52,577

Cash settlements of matured interest rate swaps


-


888


1,736


3,523

Depreciation, depletion and amortization


31,251


29,112


105,969


106,073

Accretion expense on obligations


2,050


1,201


5,598


4,835

Amortization of VPP


(1,196)


-


(1,196)


-

Gain on derivatives, net


(26,739)


(102,984)


(78,145)


(99,720)

Cash settlements of matured derivative contracts


44,904


13,483


143,272


5,313

Non-cash equity-based compensation


2,366


3,944


12,001


19,289

Impairment of oil and natural gas properties


14,423


111,701


136,667


113,968

Impairment of goodwill


65,924


-


65,924


-

Non-cash inventory write down expense


973


82


1,122


136

Dry hole and exploration costs


1,975


783


3,695


6,726

Gain on sales of oil and natural gas properties


(20)


(31,834)


(551)


(33,319)

Loss on settlement of contract


1,210


-


1,210


-

Gain on early extinguishment of debt


(24,024)


-


(24,024)


-

Loss on sale of investment in unconsolidated affiliates, contained in Other income, net


-


-


358


-

Adjusted EBITDAX


$ 52,724


$ 55,424


$ 203,869


$ 227,763










Less:









Cash income taxes


441


165


441


448

Cash interest expense, net


11,264


13,777


48,504


50,151

Realized losses on interest rate swaps


-


888


1,736


3,523

Estimated maintenance capital expenditures (1)


14,875


15,354


54,672


61,242

Distributable Cash Flow


$ 26,144


$ 25,240


$ 98,516


$ 112,399










(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.

 

Hedge Summary as of February 29, 2015





 Swap 

 Swap 

Period

Index

 Volume 

 Price 

Natural Gas (Mmmbtus)




2016

NYMEX

39,894.0

$3.57

2017

NYMEX

21,900.0

$3.24





Crude (Mbbls)




2016

WTI

366.0

$90.14





Ethane (Mbbls)




2016

Mt Belvieu

3.7

$9.14









Interest Rate Swap Agreements

 Notional Amount 

Fixed Rate



 (in $ mill) 


January 2017 - December 2017


100.0

1.039%

January 2018 - September 2020


100.0

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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