EV Energy Partners Announces Fourth Quarter and Full Year 2014 Results, Year-end Proved Reserves, and Amendment to Senior Secured Credit Facility

HOUSTON, March 2, 2015 /PRNewswire/ -- EV Energy Partners, L.P. EVEP today announced results for the fourth quarter and full year 2014 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2014 year-end proved reserves, and the amendment of its credit facility.

Full Year 2014 Results

Adjusted EBITDAX and Distributable Cash Flow for 2014 of $227.8 million and $112.4 million, increased 9 percent and 12 percent, respectively, versus 2013.  The increases in Adjusted EBITDAX and Distributable Cash Flow as compared to year-end 2013 are primarily attributable to an increase in production and in cash flows from EVEP's midstream ownership interests.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures."

Production for 2014 was 43.4 Bcf of natural gas, 1,052 MBbls of oil and 2,311 MBbls of natural gas liquids, or 174.1 million cubic feet equivalent per day (MMcfe/day).  This represents a 3 percent increase over year-end 2013 production of 169.0 MMcfe/day.

For 2014, EVEP reported net income of $129.7 million, or $2.58 per basic and diluted weighted average limited partner unit outstanding.  Included in net income were the following items:

  • $114.0 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,
  • $94.4 million of non-cash gains on commodity and interest rate derivatives,
  • $33.3 million gain on the sale of oil and natural gas properties,
  • $92.1 million gain on the sale of unconsolidated affiliates (Cardinal Gas Services LLC),
  • $19.3 million of non-cash costs contained in general and administrative expenses, and
  • $6.7 million of dry hole and exploration costs.

For 2013, EVEP reported a net loss of $76.2 million, or $(1.76) per basic and diluted weighted average limited partner unit outstanding. 

Fourth Quarter 2014 Results

Adjusted EBITDAX for the fourth quarter of 2014 was $55.4 million, a 3 percent increase over the fourth quarter of 2013 and a 10 percent decrease compared to the third quarter of 2014. Distributable Cash Flow for the fourth quarter of 2014 was $25.2 million, a 5 percent decrease from the fourth quarter of 2013 and a 22 percent decrease from the third quarter of 2014. The decrease from the third quarter of 2014 was primarily attributable to lower realized commodity prices, lower production, increased costs and lower cash flows from EVEP's midstream ownership interests due to the sale of its interest in Cardinal Gas Services.

Production for the fourth quarter of 2014 was 10.6 Bcf of natural gas, 263 MBbls of oil and 597 MBbls of natural gas liquids, or 170.9 MMcfe/day. This is essentially flat from fourth quarter 2013 production of 170.5 MMcfe/d and a 3 percent decrease from third quarter 2014 production of 175.8 MMcfe/day.  The decrease was due to a compressor change out program by the operator of certain West Virginia oil and gas properties, which reduced production for the quarter by an average of 1.9 MMcfe/day, and the timing of well completions in the Barnett Shale.

EVEP reported net income of $102.4 million, or $2.03 per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2014. Included in net income were the following items:

  • $111.7 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,
  • $89.5 million of non-cash losses on commodity and interest rate derivatives,
  • $31.8 million gain on the sale of oil and natural gas properties,
  • $92.1 million gain on the sale of unconsolidated affiliates (Cardinal Gas Services LLC), and
  • $3.9 million of non-cash costs contained in general and administrative expenses.

For the third quarter of 2014, EVEP reported net income of $42.6 million, or $0.85 per basic and diluted weighted average limited partner unit outstanding.  For the fourth quarter of 2013, EVEP reported a net loss of $50.2 million, or $(1.06) per basic and diluted weighted average limited partner unit outstanding.

Year-end 2014 Estimated Net Proved Reserves

EVEP's year-end 2014 estimated net proved reserves were 1,000.5 Bcfe.  Approximately 71 percent were natural gas, 22 percent were natural gas liquids and 7 percent were crude oil.  In addition, 84% percent were categorized as proved developed.  Year-end 2014 estimated proved reserves declined by 191 Bcfe from year-end 2013 estimated net proved reserves, primarily due to a reduction in proved undeveloped reserves (PUD's).  In connection with the annual reserves review for 2014, the significantly lower commodity price environment and related capital constraints caused EVEP to defer 213 Bcfe of PUD's and classify them as revisions.  The 213 Bcfe of revisions relate to the deferral of 356 locations EVEP had planned to drill within five years as of year-end 2013, but which now are not scheduled to be developed within the next five years.  These locations are technically proved and economic to develop at prevailing commodity prices and costs, and EVEP may drill these wells in the future, depending on future drilling costs, commodity prices and capital to finance the drilling operations.

At December 31, 2014, the present value of future net pre-tax cash flows discounted at 10 percent was $1,101.2 million and the standardized measure of estimated net proved reserves was $1,093.3 million. Standardized measure (a non-GAAP measure) includes approximately $7.9 million of present value of future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because EVEP is a partnership and is not subject to federal income taxes. The prices used in determining estimated net proved reserves at December 31, 2014 were $94.99 per Bbl of oil and $4.35 per MMBtu of natural gas as compared to $96.78 per Bbl of oil and $3.67 per MMBtu of natural gas at December 31, 2013. 


Estimated Net Proved Reserves


Crude Oil
(MMBbls)


Natural
Gas (Bcf)


NGL's
(MMBbls)


Natural Gas
Equivalents
(Bcfe)

PV 10

Barnett Shale

0.6


412.8


26.7


576.7

521.2

Appalachia Basin

5.1


94.4


2.0


137.1

207.2

Mid-Continent area

2.3


39.8


1.0


59.8

106.9

Monroe Field

-


52.5


-


52.5

26.7

San Juan Basin

0.8


34.1


2.2


51.9

49.1

Michigan

-


51.1


-


51.3

37.3

Central Texas

2.7


16.9


1.7


43.2

108.9

Permian Basin

0.4


10.6


2.5


28.0

43.9

Total 

11.9


712.2


36.1


1,000.5

1,101.2

2014 capital spending of $105.3 million added SEC proved reserves of 92.0 Bcfe, resulting in a cost of $1.14 per Mcfe and reserve replacement of 145%.

Amendment to Senior Secured Credit Facility

EVEP recently entered into an amendment to its senior secured credit facility that, among other things, extends the maturity of the facility to February 2020 and extends the senior secured debt to EBITDAX covenant of 3.5 to 1.0 through March 31, 2016.  The borrowing base was reduced from $730 million to $650 million with the next redetermination scheduled for October 2015. 

"We are pleased to have completed the amendment to our credit facility, which included an extension to the facility's maturity as well as the senior secured debt to EBITDAX covenant.  As we move forward in 2015, we are very focused on the acceleration of our UEO monetization process and on the reduction of both capital and operating costs given the current commodity price environment," said Michael Mercer, President and CEO.

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

EVEP's financial statements and related footnotes are available on our 2014 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 after March 10, 2015 will be unitholders' Schedule K-1's for the tax year 2014.  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 February 23, 2015, EV Energy Partners, L.P. will host an investor conference call on March 2, 2015, at 9 a.m. Eastern Standard Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-800-810-0924 (quote conference ID 7185919) 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)

Logo - http://photos.prnewswire.com/prnh/20130415/DA94198LOGO

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 our midstream investments, future plans, our reserve quantities and the present value of our reserves, estimates of maintenance capital 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. 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 (including the Utica Shale), changes in the metrics and procedures used to value midstream assets, exploration and development activities in the Utica Shale and elsewhere, 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. 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,



2014


2013


2014


2013

Production data:









Oil (MBbls)


263


240


1,052


1,027

Natural gas liquids (MBbls)


597


580


2,311


2,146

Natural gas (MMcf)


10,565


10,772


43,363


42,651

Net production (MMcfe)


15,722


15,690


63,540


61,690

Average sales price per unit: (1)









Oil (Bbl)


$ 69.91


$ 93.52


$ 89.15


$ 95.62

Natural gas liquids (Bbl)


22.54


33.22


28.81


30.86

Natural gas (Mcf)


3.53


3.33


4.02


3.43

Mcfe


4.39


4.94


5.27


5.04

Average unit cost per Mcfe:









Production costs:









Lease operating expenses


$ 1.77


$ 1.66


$ 1.66


$ 1.69

Production taxes


0.16


0.17


0.19


0.19

Total


1.93


1.83


1.85


1.88

Asset retirement obligations accretion expense


0.08


0.08


0.08


0.08

Depreciation, depletion and amortization


1.85


1.75


1.67


1.85

General and administrative expenses


0.65


0.64


0.71


0.66


(1) Prior to $14.4 million and $9.2 million of net hedge gains and settlements on commodity derivatives for the three months ended December 31, 2014 and December 31, 2013, respectively, and $8.8 million and $33.5 million for the twelve months ended December 31, 2014 and December 31, 2013, respectively.

 

Consolidated Balance Sheets





(In $ thousands, except number of units)












December 31, 2014


December 31, 2013

ASSETS





Current assets:





Cash and cash equivalents


$ 8,255


$ 11,698

Accounts receivable:





Oil, natural gas and natural gas liquids revenues


32,758


37,661

Related party


1,043


2,873

Other


4,570


1,111

Derivative asset


113,044


13,543

Other current assets


2,000


6,916

Assets held for sale


-


8,012

Total current assets


161,670


81,814






Oil and natural gas properties, net of accumulated 





depreciation, depletion and amortization; December 31,





 2014, $778,679; December 31, 2013, $569,770


1,710,925


1,829,062

Other property, net of accumulated depreciation 





and amortization; December 31, 2014, $898; 





December 31, 2013, $754


1,141


1,259

Restricted Cash


33,768


-

Long–term derivative asset


20,647


29,088

Investments in unconsolidated affiliates


315,491


254,978

Other assets


5,561


8,782

Total assets


$ 2,249,203


$ 2,204,983











LIABILITIES AND OWNERS' EQUITY










Current liabilities:





Accounts payable and accrued liabilities


$ 47,878


$ 46,876

Derivative liability


-


3,348

Liabilities related to assets held for sale


-


2,155

Total current liabilities


47,878


52,379






Asset retirement obligations


103,832


99,133

Long–term debt


1,030,391


980,297

Other long–term liabilities


989


1,241






Commitments and contingencies










Owners' equity:





Common unitholders - 48,572,019 units and 





48,349,080 units issued and outstanding as of 





December 31, 2014 and 2013, respectively


1,077,826


1,083,718

General partner interest


(11,713)


(11,785)

Total owners' equity


1,066,113


1,071,933

Total liabilities and owners' equity


$ 2,249,203


$ 2,204,983

 

Consolidated Statements of Operations





(In $ thousands, except per unit data)
















Three Months Ended    December 31,


Twelve Months Ended        December 31,






2014


2013


2014


2013

Revenues:









Oil, natural gas and natural gas liquids revenues


$ 69,090


$ 77,558


$ 334,729


$ 310,883

Transportation and marketing–related revenues


1,085


1,036


4,676


4,429

Total revenues


70,175


78,594


339,405


315,312










Operating costs and expenses: 









Lease operating expenses


27,777


25,969


105,781


104,465

Cost of purchased natural gas


808


756


3,533


3,242

Dry hole and exploration costs


783


(89)


6,726


2,380

Production taxes


2,462


2,725


11,976


11,476

Asset retirement obligations accretion expense 


1,200


1,181


4,835


4,925

Depreciation, depletion and amortization


29,112


27,379


106,073


113,818

General and administrative expenses


10,221


10,006


44,955


40,677

Impairment of oil and natural gas properties


111,701


77,200


113,968


85,341

Gain on sales of oil and natural gas properties


(31,834)


(41,309)


(33,319)


(41,309)

Total operating costs and expenses


152,231


103,818


364,528


325,015










Operating loss 


(82,055)


(25,224)


(25,123)


(9,703)










Other income (expense), net:









Gain (loss) on derivatives, net


102,984


(12,848)


99,720


(17,262)

Interest expense


(14,385)


(11,771)


(52,578)


(49,062)

Gain on sale of investment in unconsolidated affiliates


92,121


-


92,121


-

Other (expense) income, net


155


45


294


277

Total other income (expense), net 


180,874


(24,574)


139,557


(66,047)










Income (loss) before income taxes and
income (loss) from unconsolidated affiliates


98,819


(49,798)


114,434


(75,750)

Income taxes


(652)


193


(476)


(133)

Income (loss) before income (loss) from unconsolidated affiliates


98,167


(49,605)


113,958


(75,883)

Income (loss) from unconsolidated affiliates


4,209


(581)


15,762


(344)

Net income (loss)


$ 102,376


($ 50,186)


$ 129,720


($ 76,227)










Net loss per limited partner unit:









Basic


$ 2.03


($ 1.06)


$ 2.58


($ 1.76)

Diluted


$ 2.03


($ 1.06)


$ 2.58


($ 1.76)

Weighted average limited partner units outstanding:









Basic


48,572


46,974


48,563


43,691

Diluted


48,572


46,974


48,563


43,691










Distributions declared per unit


$ 0.500


$ 0.771


$ 2.819


$ 3.078

 

Consolidated Statements of Cash Flows





(In $ thousands)







Twelve Months Ended December 31,





2014


2013

Cash flows from operating activities:





Net income (loss)


$ 129,720


($ 76,227)

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





Dry hole costs


4,141


616

Asset retirement obligations accretion expense


4,835


4,925

Depreciation, depletion and amortization


106,073


113,818

Equity–based compensation


19,289


17,470

Impairment of oil and natural gas properties


113,968


85,341

Gain on sales of oil and natural gas properties


(33,319)


(41,309)

(Loss) gain on derivatives, net


(99,720)


17,262

Cash settlements of matured derivative contracts


5,313


30,066

Amortization of deferred loan costs


2,333


2,333

Gain on sale of unconsolidated affiliates


(92,121)


-

(Income) loss from unconsolidated affiliates


(15,762)


344

Distributions from unconsolidated affiliates


337


285

Other


(700)


(296)

Changes in operating assets and liabilities:





Accounts receivable


3,275


(2,671)

Other current assets


(1,203)


(68)

Accounts payable and accrued liabilities


2,368


1,316

Other, net


(627)


(706)

Net cash flows provided by operating activities


148,200


152,499






Cash flows from investing activities:





Final settlement of purchase price of oil and natural gas properties


-


(57,976)

Additions to oil and natural gas properties 


(102,761)


(97,946)

Prepaid drilling costs


(2,501)


(5,041)

Proceeds from sale of oil and natural gas properties


45,183


44,056

Proceeds from sale of unconsolidated affiliates


161,093


-

Restricted Cash


(33,768)


-

Investments in unconsolidated affiliates


(114,108)


(221,101)

Distributions from unconsolidated affiliates


48


38

Net cash flows used in investing activities


(46,814)


(337,970)






Cash flows from financing activities:





Long-term debt borrowings


209,000


329,000

Repayment of long-term debt borrowings


(159,000)


(208,000)

Proceeds from public equity offerings


-


204,527

Offering costs


-


(226)

Contributions from general partner


154


4,508

Distributions paid


(154,978)


(140,126)

Other


(5)


-

Net cash flows provided by financing activities


(104,829)


189,683






Increase in cash and cash equivalents


(3,443)


4,212

Cash and cash equivalents – beginning of period


11,698


7,486

Cash and cash equivalents – end of period


$ 8,255


$ 11,698

 

Non GAAP Measures

We define Adjusted EBITDAX as net income (loss) plus equity in loss (income) from unconsolidated affiliates, EBITDAX from unconsolidated affiliates, income taxes, interest expense, net, cash settlements of matured interest rate swaps, depreciation, depletion and amortization, asset retirement obligations accretion expense, loss (gain) on derivatives, net, cash settlements of matured derivative contracts, non-cash equity compensation expense, impairment of oil and natural gas properties, non-cash inventory write down expense, dry hole and exploration costs, gain on sales of oil and natural gas properties, and gain on sales of investment in unconsolidated affiliate. 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 Income (Loss) to Adjusted EBITDAX and Distributable Cash Flow

(In $ thousands)




















Three Months Ended       December 31,


Twelve Months Ended         December 31,






2014


2013


2014


2013










Net income (loss)


$ 102,376


($ 50,186)


$ 129,720


($ 76,227)










Add:









Equity in (income) loss from unconsolidated affiliates


(4,209)


581


(15,762)


344

EBITDAX from unconsolidated affiliates 


7,966


974


26,049


2,264

Income taxes


652


(193)


476


133

Interest expense, net


14,385


11,769


52,577


49,057

Cash settlements of matured interest rate swaps


888


874


3,523


3,476

Depreciation, depletion and amortization


29,112


27,379


106,073


113,818

Asset retirement obligations accretion expense


1,200


1,181


4,835


4,925

Loss (gain) on derivatives, net


(102,984)


12,848


(99,720)


17,262

Cash settlements of matured derivative contracts


13,483


8,317


5,313


30,066

Non-cash equity compensation expense


3,944


4,391


19,289


17,470

Impairment of oil and natural gas properties


111,701


77,200


113,968


85,341

Non-cash inventory write down expense


82


-


136


-

Dry hole and exploration costs


783


(89)


6,726


2,380

Gain on sales of oil and natural gas properties


(31,834)


(41,309)


(33,319)


(41,309)

Gain on sales of investment in unconsolidated affiliate


(92,121)


-


(92,121)


-

Adjusted EBITDAX


$ 55,424


$ 53,737


$ 227,763


$ 209,001










Less:









Cash income taxes (1)


165


155


448


203

Cash interest expense, net


13,777


11,164


50,151


46,646

Cash settlement of interest rate swaps


888


874


3,523


3,476

Estimated maintenance capital expenditures (2)


15,354


14,850


61,242


58,047

Distributable Cash Flow


$ 25,240


$ 26,694


$ 112,399


$ 100,629


(1) Does not include any cash taxes resulting from a gain on the sale of assets.

(2) 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.

EV Energy Partners, L.P., Houston
Michael E. Mercer
713-651-1144
http://www.evenergypartners.com

 

To view the original version on PR Newswire, visit:http://www.prnewswire.com/news-releases/ev-energy-partners-announces-fourth-quarter-and-full-year-2014-results-year-end-proved-reserves-and-amendment-to-senior-secured-credit-facility-300043270.html

SOURCE EV Energy Partners, L.P.

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