News Press Releases

EV Energy Partners Announces Third Quarter 2017 Results and Operational Update

November 9, 2017

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

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	-	$	-	$	-