HOUSTON, Aug. 11, 2014 /PRNewswire/ -- EV Energy Partners, L.P. (NASDAQ: EVEP) announced results for the second quarter 2014 and filed its Form 10-Q with the Securities and Exchange Commission. EVEP also provided an update on midstream guidance for the remainder of 2014, an update on its commodity hedge positions, and an agreement to sell certain Eagle Ford formation rights.
Agreement to Sell Eagle Ford Formation Rights
EVEP announced that it, along with certain institutional partnerships managed by EnerVest, Ltd., has signed an agreement to sell certain deep rights in the Eagle Ford formation in Burleson, Brazos and Grimes Counties to an undisclosed buyer for net proceeds to EVEP of $30 million ($218 million for all EnerVest-affiliated entities combined). EVEP and EnerVest institutional partnerships will retain all non-Eagle Ford formation rights, including the Austin Chalk formation and corresponding production. The transaction is expected to close by October 15th and is subject to customary closing conditions and purchase price adjustments.
Mark Houser, President and CEO said, "With the development of the East Texas Eagle Ford under our Austin Chalk acreage and the rapid build-up of drilling rigs and capital requirements, we decided to capitalize on the opportunity and have entered into an agreement to sell our Eagle Ford formation rights in three of the counties where there has been significant activity to date. We plan to redeploy the proceeds in acquiring longer-life, high PDP content reserves. Our remaining position in Lee, Fayette and Washington Counties will be retained until more drilling activity has occurred to assess the potential in these counties."
Second Quarter 2014 Results
Adjusted EBITDAX for the second quarter of 2014 was $54.4 million, a 3 percent increase over the second quarter of 2013, and a 3 percent decrease from the first quarter of 2014. Distributable Cash Flow for the second quarter of 2014 was $26.4 million, a 1 percent increase over the second quarter of 2013 and an 8 percent decrease from the first quarter of 2014. Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under "Non-GAAP Measures." The quarter over quarter decrease in adjusted EBITDAX and distributable cash flow is primarily attributable to lower realized NGL and natural gas prices, partially offset by an increase in midstream EBITDAX and a decrease in cash general and administrative expenses.
Production for the second quarter of 2014 was 11.0 Bcf of natural gas, 255 MBbls of oil and 571 MBbls of natural gas liquids, or 174.9 MMcfe/day. This represents a 2 percent increase over second quarter 2013 production of 172.3 MMcfe/day and flat to first quarter 2014 production of 174.7 MMcfe/day.
EVEP reported a net loss of $9.0 million, or $(0.19) per basic and diluted weighted average limited partner unit outstanding, for the second quarter of 2014. Included in net loss were the following items:
- $12.4 million of non-cash losses on commodity and interest rate derivatives,
- $6.6 million of non-cash costs contained in general and administrative expenses,
- $1.1 million of non-cash leasehold impairment charges, and
- $1.7 million of dry hole and exploration costs.
For the first quarter of 2014, EVEP reported a net loss of $6.3 million, or $(0.14) per basic and diluted weighted average limited partner unit outstanding. For the second quarter of 2013, EVEP reported a net income of $32.9 million, or $0.74 per basic and diluted weighted average limited partner unit outstanding.
Updated Midstream Guidance
Due to the timing of connection of volumes into the Cardinal Gas Services gathering system and the related throughput volumes into the Utica East Ohio processing and fractionation facilities, we are adjusting third and fourth quarter guidance ranges for Utica Shale midstream and overriding royalty interest EBITDAX as follows:
($ in Millions)
3Q 2014 $7 – $10
4Q 2014 $9 – $12
Quarterly Report on Form 10-Q
EVEP's financial statements and related footnotes are available in the second quarter 2014 Form 10-Q, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.
Conference Call
As announced on July 31, 2014, EV Energy Partners, L.P. will host an investor conference call on August 11, 2014, at 9 a.m. Eastern Time (8 a.m. Central). Investors interested in participating in the call may dial 1-888-778-9069 (quote conference ID 3368805) 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://ir.evenergypartners.com/events.cfm.
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.
Logo - http://photos.prnewswire.com/prnh/20130415/DA94198LOGO
(code #: EVEP/G)
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 the sale of our Utica Shale and Eagle Ford assets, our midstream investments and expansion plans, 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 and Eagle Ford assets), 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.
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Operating Statistics
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Three Months Ended June 30,
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Six Months Ended June 30,
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2014
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2013
|
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2014
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2013
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Production data:
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Oil (MBbls)
|
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255
|
|
245
|
|
520
|
|
508
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|
Natural gas liquids (MBbls)
|
|
571
|
|
526
|
|
1,121
|
|
1,029
|
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Natural gas (MMcf)
|
|
10,962
|
|
11,057
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|
21,798
|
|
21,324
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Net production (MMcfe)
|
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15,920
|
|
15,683
|
|
31,645
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|
30,547
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Average sales price per unit: (1)
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Oil (Bbl)
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$ 98.84
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$ 92.56
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$ 96.48
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$ 93.03
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Natural gas liquids (Bbl)
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30.36
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28.83
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31.89
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|
29.59
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Natural gas (Mcf)
|
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4.16
|
|
3.84
|
|
4.42
|
|
3.53
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Mcfe
|
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5.54
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5.12
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5.76
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5.01
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Average unit cost per Mcfe:
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Production costs:
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|
|
|
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Lease operating expenses
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$ 1.64
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|
$ 1.67
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$ 1.63
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|
$ 1.71
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Production taxes
|
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0.19
|
|
0.19
|
|
0.20
|
|
0.19
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Total
|
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1.83
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|
1.86
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|
1.83
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|
1.90
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Asset retirement obligations accretion expense
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0.08
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|
0.08
|
|
0.08
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|
0.08
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Depreciation, depletion and amortization
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1.57
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|
1.76
|
|
1.62
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|
1.92
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General and administrative expenses
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0.80
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0.58
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0.79
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|
0.71
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|
|
|
|
|
|
|
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(1) Prior to ($4.5) million and $5.8 million of net hedge (losses) gains and settlements on commodity derivatives for the three months ended June 30, 2014 and June 30, 2013, respectively and ($9.8) and $18.1 for the six months ended June 30, 2014 and June 30, 2013, respectively.
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Condensed Consolidated Balance Sheets
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(In $ thousands, except number of units)
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(Unaudited)
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June 30, 2014
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December 31, 2013
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ASSETS
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Current assets:
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Cash and cash equivalents
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$ 18,665
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$ 11,698
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Accounts receivable:
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Oil, natural gas and natural gas liquids revenues
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45,760
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37,661
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Related party
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8,681
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|
2,873
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Other
|
|
182
|
|
1,111
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Derivative asset
|
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6,015
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|
13,543
|
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Other current assets
|
|
4,908
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|
6,916
|
|
Assets held for sale
|
|
-
|
|
8,012
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Total current assets
|
|
84,211
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|
81,814
|
|
|
|
|
|
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Oil and natural gas properties, net of accumulated
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|
|
|
|
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depreciation, depletion and amortization; June 30,
|
|
|
|
|
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2014, $620,939; December 31, 2013, $569,770
|
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1,826,003
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1,829,062
|
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Other property, net of accumulated depreciation
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|
|
|
|
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and amortization; June 30, 2014, $837;
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|
|
|
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December 31, 2013, $754
|
|
1,183
|
|
1,259
|
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Long–term derivative asset
|
|
11,494
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|
29,088
|
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Investments in unconsolidated affiliates
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343,198
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|
254,978
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Other assets
|
|
6,736
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|
8,782
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Total assets
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$ 2,272,825
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$ 2,204,983
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LIABILITIES AND OWNERS' EQUITY
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Current liabilities:
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Accounts payable and accrued liabilities
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$ 47,603
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|
$ 46,876
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Derivative liability
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6,486
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|
3,348
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Liabilities related to assets held for sale
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-
|
|
2,155
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Total current liabilities
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|
54,089
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|
52,379
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|
|
|
|
|
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Asset retirement obligations
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|
102,037
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|
99,133
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Long–term debt
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|
1,124,342
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|
980,297
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Long–term derivative liability
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|
997
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|
-
|
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Other long–term liabilities
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|
908
|
|
1,241
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|
|
|
|
|
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Commitments and contingencies
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|
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Owners' equity:
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Common unitholders - 48,572,019 units and
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48,349,080 units issued and outstanding as of
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June 30, 2014 and December 31, 2013,
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respectively
|
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1,003,696
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1,083,718
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General partner interest
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(13,244)
|
|
(11,785)
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Total owners' equity
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990,452
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|
1,071,933
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Total liabilities and owners' equity
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$ 2,272,825
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$ 2,204,983
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Condensed Consolidated Statements of Operations
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(In $ thousands, except per unit data)
|
|
(Unaudited)
|
|
|
|
|
|
|
|
|
|
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Three Months Ended
June 30,
|
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Six Months Ended
June 30,
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|
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2014
|
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2013
|
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2014
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2013
|
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Revenues:
|
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Oil, natural gas and natural gas liquids revenues
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$ 88,125
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$ 80,332
|
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$ 182,199
|
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$ 153,001
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Transportation and marketing–related revenues
|
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1,235
|
|
1,270
|
|
2,500
|
|
2,303
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Total revenues
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|
89,360
|
|
81,602
|
|
184,699
|
|
155,304
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|
|
|
|
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|
|
|
|
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Operating costs and expenses:
|
|
|
|
|
|
|
|
|
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Lease operating expenses
|
|
26,028
|
|
26,217
|
|
51,423
|
|
52,311
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|
Cost of purchased natural gas
|
|
942
|
|
951
|
|
1,912
|
|
1,694
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|
Dry hole and exploration costs
|
|
1,653
|
|
902
|
|
1,971
|
|
1,319
|
|
Production taxes
|
|
2,957
|
|
2,924
|
|
6,480
|
|
5,840
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|
Asset retirement obligations accretion expense
|
|
1,203
|
|
1,205
|
|
2,390
|
|
2,559
|
|
Depreciation, depletion and amortization
|
|
25,026
|
|
27,670
|
|
51,238
|
|
58,503
|
|
General and administrative expenses
|
|
12,749
|
|
9,121
|
|
25,047
|
|
21,743
|
|
Impairment of oil and natural gas properties
|
|
1,069
|
|
2,829
|
|
1,321
|
|
7,998
|
|
Gain on sales of oil and natural gas properties
|
|
-
|
|
-
|
|
(1,484)
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|
-
|
|
Total operating costs and expenses
|
|
71,627
|
|
71,819
|
|
140,298
|
|
151,967
|
|
|
|
|
|
|
|
|
|
|
Operating income
|
|
17,733
|
|
9,783
|
|
44,401
|
|
3,337
|
|
|
|
|
|
|
|
|
|
|
Other (expense) income, net:
|
|
|
|
|
|
|
|
|
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(Loss) gain on derivatives, net
|
|
(17,817)
|
|
34,747
|
|
(40,812)
|
|
7,233
|
|
Interest expense
|
|
(12,445)
|
|
(11,604)
|
|
(24,517)
|
|
(24,433)
|
|
Other income, net
|
|
87
|
|
55
|
|
141
|
|
242
|
|
Total other (expense) income, net
|
|
(30,175)
|
|
23,198
|
|
(65,188)
|
|
(16,958)
|
|
|
|
|
|
|
|
|
|
|
(Loss) income before income taxes and equity in
income of unconsolidated affiliates
|
|
(12,442)
|
|
32,981
|
|
(20,787)
|
|
(13,621)
|
|
Income taxes
|
|
78
|
|
(216)
|
|
333
|
|
(393)
|
|
(Loss) income before equity in income of unconsolidated affiliates
|
|
(12,364)
|
|
32,765
|
|
(20,454)
|
|
(14,014)
|
|
Equity in income of unconsolidated affiliates
|
|
3,341
|
|
89
|
|
5,178
|
|
287
|
|
Net (loss) income
|
|
($ 9,023)
|
|
$ 32,854
|
|
($ 15,276)
|
|
($ 13,727)
|
|
|
|
|
|
|
|
|
|
|
Net (loss) income per limited partner unit:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
($ 0.19)
|
|
$ 0.74
|
|
($ 0.33)
|
|
($ 0.34)
|
|
Diluted
|
|
($ 0.19)
|
|
$ 0.74
|
|
($ 0.33)
|
|
($ 0.34)
|
|
Weighted average limited partner units outstanding:
|
|
|
|
|
|
|
|
|
|
Basic
|
|
48,572
|
|
42,599
|
|
48,555
|
|
42,578
|
|
Diluted
|
|
48,572
|
|
42,659
|
|
48,555
|
|
42,578
|
|
|
|
|
|
|
|
|
|
|
Distributions declared per unit
|
|
$ 0.773
|
|
$ 0.769
|
|
$ 1.545
|
|
$ 1.537
|
|
Condensed Consolidated Statements of Cash Flows
|
|
(In $ thousands)
|
|
(Unaudited)
|
|
Six Months Ended June 30,
|
|
|
|
|
2014
|
|
2013
|
|
Cash flows from operating activities:
|
|
|
|
|
|
Net loss
|
|
($ 15,276)
|
|
($ 13,727)
|
|
Adjustments to reconcile net loss to net cash flows provided by operating activities:
|
|
|
|
|
|
Asset retirement obligations accretion expense
|
|
2,390
|
|
2,559
|
|
Depreciation, depletion and amortization
|
|
51,238
|
|
58,503
|
|
Equity–based compensation cost
|
|
11,058
|
|
8,783
|
|
Impairment of oil and natural gas properties
|
|
1,321
|
|
7,998
|
|
Gain on sales of oil and natural gas properties
|
|
(1,484)
|
|
-
|
|
Loss (gain) on derivatives, net
|
|
40,812
|
|
(7,233)
|
|
Cash settlements of matured derivative contracts
|
|
(11,555)
|
|
16,388
|
|
Equity in income of unconsolidated affiliates
|
|
(5,178)
|
|
(287)
|
|
Distributions from unconsolidated affiliates
|
|
112
|
|
62
|
|
Other
|
|
1,398
|
|
1,411
|
|
Changes in operating assets and liabilities:
|
|
|
|
|
|
Accounts receivable
|
|
(12,978)
|
|
(5,044)
|
|
Other current assets
|
|
(813)
|
|
(2,300)
|
|
Accounts payable and accrued liabilities
|
|
2,478
|
|
3,494
|
|
Other, net
|
|
(243)
|
|
(200)
|
|
Net cash flows provided by operating activities
|
|
63,280
|
|
70,407
|
|
|
|
|
|
|
Cash flows from investing activities:
|
|
|
|
|
|
Final settlement of purchase price of oil and natural gas properties
|
|
-
|
|
7,998
|
|
Additions to oil and natural gas properties
|
|
(44,865)
|
|
(51,808)
|
|
Prepaid drilling costs
|
|
(2,346)
|
|
-
|
|
Proceeds from sale of oil and natural gas properties
|
|
7,315
|
|
-
|
|
Investments in unconsolidated affiliates
|
|
(83,188)
|
|
(118,446)
|
|
Distributions from unconsolidated affiliates
|
|
34
|
|
27
|
|
Net cash flows used in investing activities
|
|
(123,050)
|
|
(162,229)
|
|
|
|
|
|
|
Cash flows from financing activities:
|
|
|
|
|
|
Long-term debt borrowings
|
|
144,000
|
|
160,000
|
|
Contributions from general partner
|
|
154
|
|
334
|
|
Distributions paid
|
|
(77,412)
|
|
(67,721)
|
|
Other
|
|
(5)
|
|
-
|
|
Net cash flows provided by financing activities
|
|
66,737
|
|
92,613
|
|
|
|
|
|
|
Increase in cash and cash equivalents
|
|
6,967
|
|
791
|
|
Cash and cash equivalents – beginning of period
|
|
11,698
|
|
7,486
|
|
Cash and cash equivalents – end of period
|
|
$ 18,665
|
|
$ 8,277
|
Non-GAAP Measures
We define Adjusted EBITDAX as net (loss) income plus equity in income of unconsolidated affiliates, EBITDAX of 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, and gain on sales of oil and natural gas properties. 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.
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Reconciliation of Net (Loss) Income to Adjusted EBITDAX and Distributable Cash Flow
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(In $ thousands)
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(Unaudited)
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Three Months Ended June 30,
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Six Months Ended June 30,
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2014
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2013
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2014
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2013
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Net (loss) income
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($ 9,023)
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$ 32,854
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($ 15,276)
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($ 13,727)
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Add:
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Equity in income of unconsolidated affiliates
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(3,341)
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(89)
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(5,178)
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(287)
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EBITDAX of unconsolidated affiliates
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5,565
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245
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9,199
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517
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Income taxes
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(78)
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216
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(333)
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393
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Interest expense, net
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12,445
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11,603
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24,517
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24,431
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Cash settlements of matured interest rate swaps
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880
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867
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1,757
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1,732
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Depreciation, depletion and amortization
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25,026
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27,670
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51,238
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58,503
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Asset retirement obligations accretion expense
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1,203
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1,205
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2,390
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2,559
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Loss (gain) on derivatives, net
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17,817
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(34,747)
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40,812
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(7,233)
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Cash settlements of matured derivative contracts
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(5,397)
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4,949
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(11,555)
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16,388
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Non-cash equity compensation expense
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6,555
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4,297
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11,058
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8,783
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Impairment of oil and natural gas properties
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1,069
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2,829
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1,321
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7,998
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Non-cash inventory write down expense
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(0)
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-
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53
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-
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Dry hole and exploration costs
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1,653
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902
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1,971
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1,319
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Gain on sales of oil and natural gas properties
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-
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-
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(1,484)
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-
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Adjusted EBITDAX
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$ 54,373
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$ 52,801
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$ 110,490
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$ 101,375
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Less:
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Cash income taxes
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(27)
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(20)
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1
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24
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Cash interest expense, net
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11,839
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11,001
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23,306
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23,227
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Realized losses on interest rate swaps
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880
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867
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1,757
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1,732
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Estimated maintenance capital expenditures (1)
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15,272
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14,741
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30,448
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28,321
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Distributable Cash Flow
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$ 26,409
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$ 26,212
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$ 54,978
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$ 48,071
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(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.
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Summary of New Hedge Positions (since May 12, 2014)
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Period
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Index
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Swap Volume
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Swap Price
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Crude
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(MmmBtus/Mbbls)
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2015
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WTI
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182.5
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$94.59
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2016
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WTI
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366.0
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$90.14
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Hedge Summary Table (as of August 8, 2014)
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Swap
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Swap
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Period
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Index
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Volume
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Price
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Natural Gas
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(MmmBtus/Mbbls)
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3Q 2014
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NYMEX
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10,009.6
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$4.70
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4Q 2014
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NYMEX
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10,009.6
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$4.66
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2015
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NYMEX
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36,317.5
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$4.94
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2016
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NYMEX
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10,980.0
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$4.17
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Crude
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3Q 2014
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WTI
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380.3
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$91.50
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4Q 2014
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WTI
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377.2
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$93.73
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2015
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WTI
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1,277.5
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$90.28
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2016
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WTI
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366.0
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$90.14
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Interest Rate Swap Agreements
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Notional Amount
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Fixed Rate
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(in $ mill)
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July 2014 - July 2015
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110.0
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3.315%
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EV Energy Partners, L.P., Houston
Michael E. Mercer
713-651-1144
http://www.evenergypartners.com
SOURCE EV Energy Partners, L.P.