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EV Energy Partners Announces Third Quarter 2017 Results and Operational Update

HOUSTON, Nov. 09, 2017 (GLOBE NEWSWIRE) -- EV Energy Partners, L.P. (NASDAQ:EVEP) today announced results for the third quarter of 2017 and the filing of its Form 10-Q with the Securities and Exchange Commission. In addition, EVEP announced its borrowing base was reduced from $375 million to $325 million during its semi-annual borrowing base review. Further, the Company has provided an update on initial drilling results in multiple areas of focus and added commodity hedges to the portfolio.

Third Quarter 2017 Results

For the third quarter of 2017, EVEP reported a net loss of $17.9 million, or $(0.36) per basic and diluted weighted average limited partner unit outstanding, compared to a net loss of $25.2 million, or $(0.50) per basic and diluted weighted average limited partner unit outstanding, for the second quarter of 2017. For the third quarter of 2016, EVEP reported a net loss of $19.2 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding. Included in the 2017 third quarter net loss were the following items:

  • $1.1 million of non-cash costs contained in general and administrative expenses,
  • $0.9 million of gain on sales of oil and natural gas properties, and
  • $0.9 million of non-cash losses on commodity and interest rate derivatives.

Production for the third quarter of 2017 was 10.3 Bcf of natural gas, 310 Mbbls of oil and 541 Mbbls of natural gas liquids (NGLs), or 167.1 million cubic feet equivalent per day (Mmcfe/day). This represents a 14 percent decrease from the third quarter of 2016 production of 195.3 Mmcfe/d and a three percent decrease from the second quarter of 2017 production of 171.9 Mmcfe/day. The decrease in production from the third quarter of 2016 was primarily due to significantly lower drilling activity in 2016 and the divestiture of producing properties completed on December 1, 2016, partially offset by the addition of Karnes County, TX, producing properties acquired on January 31, 2017. The decrease in production from the second quarter of 2017 was primarily due to timing on completion of wells in the 2017 drilling program.

Adjusted EBITDAX for the third quarter of 2017 was $17.0 million, a 35 percent decrease from the third quarter of 2016 and a 22 percent decrease from the second quarter of 2017. EVEP reported Distributable Cash Flow of $(1.1) million for the third quarter of 2017. The decreases in Adjusted EBITDAX and Distributable Cash Flow from the third quarter of 2016 were primarily attributable to decreased realized hedge gains, decreased natural gas and natural gas liquids production and higher operating expenses, partially offset by higher realized oil, natural gas and natural gas liquids prices. The decreases in Adjusted EBITDAX and Distributable Cash Flow from the second quarter of 2017 were primarily attributable to lower realized natural gas prices, higher lease operating and cash general and administrative expenses and decreased oil production, partially offset by realized hedge gains. Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under “Non-GAAP Measures.”

Credit Facility and Liquidity Update

In October, the borrowing base under the Company’s credit facility decreased from $375 million to $325 million. As of November 7, 2017, EVEP had total debt of $606 million, which included $263 million outstanding under the credit facility and $343 million in outstanding Senior Notes due 2019. Liquidity from borrowing base capacity and cash on hand is currently over $65 million. EVEP’s next semi-annual borrowing base redetermination is scheduled for April 2018. For more information regarding EVEP’s debt and liquidity, please review EVEP’s Quarterly Report on Form 10-Q filed today with the Securities and Exchange Commission.

Operations Update

In September, the Neva #2, an Austin Chalk well in Washington County, Texas, came online with a 24 hour initial production (IP) peak test of 2,529 barrels of oil equivalent per day (boe/d). The product mix was approximately 29 percent oil, 45 percent NGLs, and 26 percent natural gas. The well was choked back due to pipeline constraints, but had a 30-day IP of 1,556 boe/d (19 percent oil, 27 percent NGLs, 54 percent natural gas). EVEP’s working interest in the well is approximately 15 percent. There are three additional Austin Chalk wells included in EVEP’s 2017 capital program. One well has been drilled and completed and is scheduled to begin flowback this week. Another well has been drilled and is awaiting completion, and the final well is currently being drilled. EVEP’s working interest ranges from 13 to 19 percent.

Additionally, 12 wells began flowback on EVEP’s Karnes County, Texas, properties in September. The average 30-day IP was 1,950 boe/d per well. The production mix was approximately 84 percent oil, 9 percent natural gas liquids, and 7 percent natural gas. EVEP expects 13 additional wells to come online before the end of the year. EVEP’s average working interest in these wells is approximately 4.5 percent.

In the Barnett Shale, nine wells recently began flowback. EVEP’s average working interest in the Barnett wells is approximately 31 percent.

Additional Commodity Hedges

EVEP entered into the following additional commodity hedges in November subsequent to its press release on August 9, 2017. 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
Crude (MBbls):
Dec 2017 - Mar 2018 WTI 157.3 $ 57.40
Propane (MBbls):
Oct - Dec 2017 Mt Belvieu 55.2 $ 36.91
Jan - Mar 2018 Mt Belvieu 117.0 $ 36.12

Quarterly Report on Form 10-Q

EVEP’s financial statements and related footnotes are available in the third quarter 2017 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 October 17, 2017, EV Energy Partners, L.P. will host an investor conference call on November 9, 2017, at 9 a.m. Eastern Time (8 a.m. Central). Investors interested in participating in the call may dial 1-888-857-6931 (quote conference ID 4841275) 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, liquidity, 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 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 Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Production data:
Oil (MBbls) 310 308 1,018 938
Natural gas liquids (MBbls) 541 597 1,581 1,784
Natural gas (MMcf) 10,263 12,535 30,869 38,304
Net production (MMcfe) 15,373 17,965 46,460 54,637
Average sales price per unit: (1)
Oil (Bbl) $ 45.03 $ 40.40 $ 45.34 $ 36.82
Natural gas liquids (Bbl) 21.27 14.23 20.15 14.09
Natural gas (Mcf) 2.59 2.38 2.78 1.86
Mcfe 3.38 2.82 3.52 2.39
Average unit cost per Mcfe:
Production costs:
Lease operating expenses $ 1.73 $ 1.42 $ 1.65 $ 1.47
Production taxes 0.17 0.12 0.17 0.10
Total 1.90 1.54 1.82 1.57
Depreciation, depletion and amortization 1.41 1.76 1.51 1.67
General and administrative expenses 0.51 0.47 0.47 0.46

(1) Prior to $0.7 million and $10.1 million of net hedge gains on settlements of commodity derivatives for the three months ended September 30, 2017 and 2016, respectively, and $2.2 million of net hedge losses and $49.1 million of net hedge gains on settlements of commodity derivatives for the nine months ended September 30, 2017 and 2016, respectively.


Condensed Consolidated Balance Sheets
(In $ thousands, except number of units)
(Unaudited)

September 30, December 31,
2017 2016
ASSETS
Current assets:
Cash and cash equivalents $ 13,910 $ 5,557
Accounts receivable:
Oil, natural gas and natural gas liquids revenues 42,350 39,629
Related party - 745
Other 1,071 2,451
Derivative asset 743 201
Other current assets 4,791 3,718
Total current assets 62,865 52,301
Oil and natural gas properties, net of accumulated depreciation, depletion and
amortization; September 30, 2017, $1,162,695; December 31, 2016, $1,051,600 1,411,739 1,497,211
Other property, net of accumulated depreciation and amortization;
September 30, 2017, $1,037; December 31, 2016, $1,002 971 996
Restricted cash - 52,076
Long-term derivative assets 193 -
Other assets 3,577 4,186
Total assets $ 1,479,345 $ 1,606,770
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party $ 47,653 $ 31,700
Related party 4,481 5,797
Derivative liability 586 21,679
Total current liabilities 52,720 59,176
Asset retirement obligations 161,371 180,241
Long–term debt, net 596,397 606,948
Long–term derivative liability - 955
Other long–term liabilities 1,040 1,043
Commitments and contingencies
Owners’ equity:
Common unitholders – 49,368,869 units and 49,055,214 units issued and
outstanding as of September 30, 2017 and December 31, 2016, respectively 687,380 776,158
General partner interest (19,563) (17,751)
Total owners’ equity 667,817 758,407
Total liabilities and owners’ equity $ 1,479,345 $ 1,606,770



Condensed Consolidated Statements of Operations
(In $ thousands, except per unit data)
(Unaudited)

Three Months Ended Nine Months Ended
September 30, September 30,
2017 2016 2017 2016
Revenues:
Oil, natural gas and natural gas liquids revenues $ 52,022 $ 50,750 $ 163,745 $ 130,854
Transportation and marketing–related revenues 629 622 1,945 1,599
Total revenues 52,651 51,372 165,690 132,453
Operating costs and expenses:
Lease operating expenses 26,608 25,571 76,782 80,532
Cost of purchased natural gas 444 435 1,384 1,076
Dry hole and exploration costs 135 294 190 1,195
Production taxes 2,573 2,126 7,828 5,501
Accretion expense on obligations 1,905 2,057 5,774 6,146
Depreciation, depletion and amortization 21,710 31,639 70,221 91,492
General and administrative expenses 7,912 8,514 21,631 24,862
Impairment of oil and natural gas properties 32 687 68,016 3,371
Gain on settlement of contract - - - (3,185)
Gain on sales of oil and natural gas properties (876) - (911) -
Total operating costs and expenses 60,443 71,323 250,915 210,990
Operating loss (7,792) (19,951) (85,225) (78,537)
Other income (expense), net:
Gain (loss) on derivatives, net (152) 8,559 20,588 (17,192)
Interest expense (10,092) (9,889) (30,501) (32,554)
Gain on early extinguishment of debt - - - 47,695
Other income, net 68 622 1,149 1,586
Total other income (expense), net (10,176) (708) (8,764) (465)
Loss before income taxes (17,968) (20,659) (93,989) (79,002)
Income taxes 80 1,429 109 1,779
Net loss $ (17,888) $ (19,230) $ (93,880) $ (77,223)
Basic and diluted earnings per limited partner unit:
Net loss $ (0.36) $ (0.38) $ (1.86) $ (1.54)
Weighted average limited partner units outstanding
(basic and diluted) 49,369 49,055 49,353 49,046



Condensed Consolidated Statements of Cash Flows
(In $ thousands)
(Unaudited)

Nine Months Ended
September 30,
2017 2016
Cash flows from operating activities:
Net loss $ (93,880) $ (77,223)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Amortization of volumetric production payment liability - (3,070)
Accretion expense on obligations 5,774 6,146
Depreciation, depletion and amortization 70,221 91,492
Equity–based compensation cost 3,290 4,853
Impairment of oil and natural gas properties 68,016 3,371
Gain on sales of oil and natural gas properties (911) -
(Gain) loss on derivatives, net (20,588) 17,192
Cash settlements of matured derivative contracts (2,196) 46,299
Gain on early extinguishment of debt - (47,695)
Other 820 1,822
Changes in operating assets and liabilities:
Accounts receivable 1,681 (8,597)
Other current assets (649) (291)
Accounts payable and accrued liabilities 2,993 4,158
Income taxes - (11,657)
Other, net (235) (277)
Net cash flows provided by operating activities 34,336 26,523
Cash flows from investing activities:
Acquisition of oil and natural gas properties (61,400) -
Additions to oil and natural gas properties (9,344) (14,266)
Proceeds from sale of oil and natural gas properties 3,639 2,420
Cash settlements from acquired derivative contracts - 2,823
Restricted cash 52,076 -
Other 46 33
Net cash flows used in investing activities (14,983) (8,990)
Cash flows from financing activities:
Repayment of long-term debt borrowings (28,000) (41,000)
Long–term debt borrowings 17,000 48,000
Redemption of Senior Notes due 2019 - (34,978)
Loan costs incurred - (121)
Distributions paid - (3,868)
Net cash flows used in financing activities (11,000) (31,967)
Increase (decrease) in cash and cash equivalents 8,353 (14,434)
Cash and cash equivalents – beginning of year 5,557 20,415
Cash and cash equivalents – end of period $ 13,910 $ 5,981



Non­­-GAAP Measures

We define Adjusted EBITDAX as net loss plus income taxes, interest expense, net, depreciation, depletion and amortization, accretion expense on obligations, amortization of volumetric production payment (VPP), (gain) loss on derivatives, net, cash settlements of matured commodity derivative contracts, non-cash equity-based compensation, impairment of oil and natural gas properties, non-cash oil inventory adjustment, dry hole and exploration costs, gain on settlement of contract, gain on early extinguishment of debt, gain on sales of oil and natural gas properties, and other income, net. Distributable Cash Flow is defined as Adjusted EBITDAX less cash income taxes, cash interest expense, net, realized (gains) 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 Loss to Adjusted EBITDAX and Distributable Cash Flow
(In $ thousands)
(Unaudited)

Three Months Ended Nine Months Ended
Sep 30, 2017 Sep 30, 2016 Jun 30, 2017 Sep 30, 2017 Sep 30, 2016
Net loss $ (17,888) $ (19,230) $ (25,161) $ (93,880) $ (77,223)
Add:
Income taxes (80) (1,429) (66) (109) (1,779)
Interest expense, net 10,092 9,889 10,435 30,501 32,544
Depreciation, depletion and amortization 21,710 31,639 21,531 70,221 91,492
Accretion expense on obligations 1,905 2,057 1,870 5,774 6,146
Amortization of VPP - (1,027) - - (3,070)
(Gain) loss on derivatives, net 152 (8,559) (6,511) (20,588) 17,192
Cash settlements of matured commodity
derivative contracts 684 10,117 (404) (2,173) 49,122
Non-cash equity-based compensation 1,086 1,889 1,019 3,290 4,853
Impairment of oil and natural gas properties 32 687 18,397 68,016 3,371
Non-cash oil inventory adjustment - - 424 424 123
Dry hole and exploration costs 135 294 75 190 1,195
Gain on settlement of contract - - - - (3,185)
Gain on early extinguishment of debt - - - - (47,695)
Gain on sales of oil and natural gas properties (876) - - (1,108) -
Other income, net - (309) (9) - (309)
Adjusted EBITDAX 16,952 26,018 21,600 60,558 72,777
Less:
Cash income taxes - (933) - - (933)
Cash interest expense, net 9,633 9,566 9,647 28,780 29,950
Realized (gains) losses on interest rate swaps (49) - 9 23 -
Estimated maintenance capital expenditures (1) 8,500 11,000 8,500 25,500 33,000
Distributable Cash Flow $ (1,131) $ 6,385 $ 3,444 $ 6,256 $ 10,760

(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 operation 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):
Oct - Dec 2017 NYMEX 8,280.0 $ 3.07 2,760.0 $ 2.75 $ 3.27
Jan - Mar 2018 NYMEX 4,500.0 $ 3.46 - $ - $ -
Crude (MBbls):
Oct - Nov 2017 WTI 61.0 $ 52.85 - $ - $ -
Dec 2017 WTI 71.3 $ 55.42 - $ - $ -
Jan - Mar 2018 WTI 117.0 $ 57.40 - $ - $ -
Ethane (MBbls):
Oct - Dec 2017 Mt Belvieu 128.8 $ 11.66 - $ - $ -
Propane (MBbls):
Oct - Dec 2017 Mt Belvieu 119.6 $ 30.55 - $ - $ -
Jan - Mar 2018 Mt Belvieu 117.0 $ 36.12 - $ - $ -


Period Notional Amount Fixed Rate
Interest Rate Swap Agreements: ($ mil)
Oct 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

Source:EV Energy Partners, L.P.