EV Energy Partners, L.P. (NASDAQ:EVEP) today announced results for the fourth quarter and full year 2016 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2016 year-end proved reserves and 2017 guidance.

Highlights

• Overall operating results for the year in line with 2016 guidance
• Completed divestment of certain gas-weighted assets in the Barnett Shale for $52.1 million on December 1, 2016 (before post-closing purchase price adjustments) 
• Completed $58.7 million asset purchase on January 31, 2017 (before post-closing purchase price adjustments) in the Eagle Ford and Austin Chalk in Karnes County, TX using proceeds from the Barnett Shale divestiture through a like-kind exchange transaction and $6.6 million of borrowings under the credit facility
• Repurchased $82.7 million of outstanding Senior Secured Notes due April 2019 for $35 million
• Increased capital spending budget to $30 to $45 million for 2017 from $10.7 million in 2016
• Maintained significant liquidity, which is currently over $175 million, between borrowing base capacity and cash on hand

Fourth Quarter 2016 Results

For the fourth quarter 2016, EVEP reported a net loss of $165.7 million, or $(3.31) per basic and diluted weighted average limited partner unit outstanding compared to a net loss of $19.2 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding for the third quarter of 2016.  Included in net loss were the following items:

• $127.9 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 and the disposition of oil and natural gas properties,
• $27.5 million of non-cash losses on commodity and interest rate derivatives, and
• $1.8 million of non-cash costs contained in general and administrative expenses.

For the fourth quarter of 2015, EVEP reported a net loss of $71.3 million, or $(1.43) per basic and diluted weighted average limited partner unit outstanding.

Production for the fourth quarter of 2016 was 11 Bcf of natural gas, 278 Mbbls of oil and 547 Mbbls of natural gas liquids, or 173.6 million cubic feet equivalent per day (Mmcfe/day). This represents a 17 percent decrease from fourth quarter 2015 production of 209.8 Mmcfe/d and an 11 percent decrease from third quarter 2016 production of 195.3 Mmcfe/day.  The decreases were primarily due to reduced drilling activity and the divestitures completed on December 1, 2016.

Adjusted EBITDAX for the fourth quarter of 2016 was $28.5 million, a 46 percent decrease from the fourth quarter of 2015 and a 10 percent increase over the third quarter of 2016.  Distributable Cash Flow for the fourth quarter of 2016 was $7.9 million, a 70 percent decrease from the fourth quarter of 2015 and a 24 percent increase over the third quarter of 2016.  The decreases in Adjusted EBITDAX and Distributable Cash Flow from the fourth quarter of 2015 were attributable to lower realized hedge gains and lower production, partially offset by higher realized oil, natural gas and natural gas liquids prices.  The increases in Adjusted EBITDAX and Distributable Cash Flow over the third quarter of 2016 were primarily due to higher realized oil, natural gas and natural gas liquids prices and lower operating expenses, partially offset by lower production.  Adjusted EBITDAX and Distributable Cash Flow are Non-GAAP financial measures and are described in the attached table under “Non-GAAP Measures.”

Full Year 2016 Results

For 2016, EVEP reported a net loss of $242.9 million, or $(4.85) per basic and diluted weighted average limited partner unit outstanding as compared to net income of $21.3 million, or $0.41 per basic and diluted weighted average limited partner unit outstanding for 2015.  Included in net loss were the following items:

• $131.3 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 and the disposition of oil and natural gas properties,
• $93.8 million of non-cash losses on commodity and interest rate derivatives,
• $47.7 million of gain on early extinguishment of debt related to repurchases of Senior Notes at a discount to par,
• $6.6 million of non-cash costs contained in general and administrative expenses,
• $3.2 of gain on settlement of contract, and
• $0.7 million of dry hole and exploration costs.

Production for 2016 was 49.3 Bcf of natural gas, 1.2 Mmbbls of oil and 2.3 Mmbbls of natural gas liquids, or 192.9 Mmcfe/day, which is a 10 percent increase over 2015 production of 174.8 Mmcfe/day.  The increase over 2015 production was primarily due to the addition of producing properties acquired on October 1, 2015.

Adjusted EBITDAX and Distributable Cash Flow for 2016 of $101.3 million and $18.7 million decreased 50 percent and 81 percent, respectively, versus 2015.  The decreases in Adjusted EBITDAX and Distributable Cash Flow as compared to 2015 are primarily due to lower realized hedge gains and lower realized oil and natural gas prices, partially offset by the addition of producing properties acquired on October 1, 2015, lower operating expenses and higher realized natural gas liquids prices. 

"In 2016, our overall results were in line with guidance, we continued to reduce operating costs through the hard work of our asset teams, and we reduced debt by $83 million.  In December, we sold some of our Barnett Shale natural gas assets, and in January, redeployed the proceeds in an oil-weighted Karnes County acquisition that we believe has significantly more drilling opportunities at attractive rates of return in the current commodity price environment.  In 2017, we plan to increase our capital spending, while remaining focused on our cost structure and maintaining sufficient liquidity," said Michael Mercer, President and CEO.

Additional Commodity Hedges

EVEP entered into the following additional commodity hedges in 2016 subsequent to its press release on November 9, 2016.  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
Natural Gas (Mmmbtus)
Jan - Mar 2018		NYMEX		4,500		$3.46
Ethane (Mbbls)
2017		Mt Belvieu		511.0		$11.66
Propane (Mbbls)
2017		Mt Belvieu		255.5		$25.10

Year-end 2016 Estimated Net Proved Reserves

EVEP’s year-end 2016 estimated net proved reserves were 851 Bcfe.  Approximately 68 percent were natural gas, 23 percent were natural gas liquids and 9 percent were crude oil.  In addition, 90 percent were categorized as proved developed.  Year-end 2016 estimated net proved reserves decreased by 22 percent or 246 Bcfe from year-end 2015 estimated net proved reserves due to reduced commodity pricing, asset divestitures, and volumes produced and sold during 2016.  The prices used in determining estimated net proved reserves at December 31, 2016 were $42.75 per Bbl of oil and $2.48 per Mmbtu of natural gas as compared to $50.28 per Bbl of oil and $2.59 per Mmbtu of natural gas at December 31, 2015.

At December 31, 2016, the present value of future net pre-tax cash flows discounted at 10 percent (“PV 10”) was $373.6 million (a non-GAAP measure) and the standardized measure of estimated net proved reserves was $371.1 million.  Standardized measure is the present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”), without giving effect to non–property related expenses such as certain general and administrative expenses, debt service and future federal income tax expenses or to depreciation, depletion and amortization and discounted using an annual discount rate of 10 percent.  Our standardized measure includes approximately $2.5 million of present value of future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because we are a partnership and are not subject to federal income taxes.  We have included PV 10 because we believe it is a measure frequently utilized by investors.

EVEP’s year-end 2016 estimated net proved reserves and standardized measure are net of the recently announced divestiture of 74 Bcf of proved natural gas properties in the Barnett Shale on December 1, 2016 and prior to the acquisition of estimated net proved reserves of 35 Bcfe of Eagle Ford and Austin Chalk oil and natural gas properties in Karnes County, TX which closed on January 31, 2017.

		Estimated Net Proved Reserves
		Crude Oil (MMBbls)		Natural Gas (Bcf)		NGL's (MMBbls)		Natural Gas Equivalents (Bcfe)		PV 10 ($mm)
Barnett Shale		0.4		239.1		21.0		367.8		$	128.6
San Juan Basin		1.1		94.9		7.1		144.0			46.3
Appalachia Basin		7.2		91.7		0.3		136.4			98.4
Michigan		-		74.7		0.4		77.8			29.1
Central Texas		2.4		20.5		2.4		49.1			44.0
Monroe Field		-		27.9		-		27.9			(1.2	)
Mid-Continent area		1.1		18.9		0.4		27.8			18.9
Permian Basin		0.4		7.6		1.8		20.4			9.5
Total		12.6		575.3		33.4		851.2			373.6

For comparative purposes, utilizing NYMEX forward closing prices for oil and natural gas on December 30, 2016 (the last trading day of 2016), total NYMEX strip-based proved reserves at December 31, 2016 were 1,277 Bcfe (69 percent proved developed), with a PV 10 of $790 million, an increase of 426 Bcfe over SEC reserves and $416 million over SEC PV 10.  Also at these prices, our January 2017 Karnes County, TX acquisition had strip-based proved reserves of 38 Bcfe (21 percent proved developed), with a PV 10 of $87 million.  NYMEX strip-based proved reserves are calculated based on the SEC proved reserves estimation methodology, but applying NYMEX strip prices rather than SEC prices. We believe that the PV 10 of NYMEX strip-based reserves is useful to investors to illustrate the potential value of proved reserves that are economically recoverable in the current commodity price environment rather than SEC prices. Neither the PV 10 of our SEC reserves, the PV 10 of our NYMEX strip-based reserves nor the standardized measure represents an estimate of fair market value of our oil and natural gas properties.  

2017 Guidance

	($ in millions)				Full Year 2017
	Net Production
	Natural Gas (Mmcf)				40,720		-		45,005
	Crude Oil (Mbbls)				1,325		-		1,465
	Natural Gas Liquids (Mbbls)				2,055		-		2,270
	Total Mmcfe				61,000		-		67,415
	Average Daily Production (Mmcfe/d)				167		-		185
	Net Transportation Margin (a)			$0.5			-	$1.0
	Average Price Differential vs NYMEX
	Natural Gas ($/Mcf)			($0.37)			-	($0.25)
	Crude Oil ($/Bbl)			($5.40)			-	($3.90)
	NGL (% of NYMEX Crude Oil)				34%		-		38%
	Expenses
	Operating Expenses:
	LOE and other			$98.1			-	$108.5
	Production Taxes (as % of revenue)				4.2%		-		5.2%
							-
	General and administrative expense (b)			$22.0			-	$26.0
	Capital Expenditures (c)			$30.0			-	$45.0
	(a)  Represents estimated transportation and marketing-related revenues less cost of purchased natural gas.
	(b)  Excludes non-cash general and administrative expense, of which non-cash unit based compensation is a part, also
	excludes any amounts for future acquisition related due diligence and transaction costs.
	(c)  Represents estimates for drilling and related capital expenditures. Does not include any amounts for acquisitions of
	oil and gas properties.

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

EVEP’s financial statements and related footnotes are available on our 2016 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website by March 6, 2016 will be unitholders’ Schedule K-1’s for the tax year 2016.  For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-800-973-7551.

Conference Call

As announced on January 31, 2016, EV Energy Partners, L.P. will host an investor conference call on March 1, 2016, at 9 a.m. Eastern Standard Time (8 a.m. Central).  Investors interested in participating in the call may dial 1-888-245-0988 (quote conference ID 9028703) 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, our reserve quantities and the present value of our reserves, estimates of maintenance capital and production amounts, the information under the heading “2017 Guidance” 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 December 31,						Twelve Months Ended December 31,
				2016			2015			2016			2015
	Production data:
	Oil (Mbbls)			278			351			1,216			1,041
	Natural gas liquids (Mbbls)			547			655			2,331			2,326
	Natural gas (Mmcf)			11,029			13,266			49,333			43,592
	Net production (Mmcfe)			15,975			19,301			70,612			63,792
	Average sales price per unit: (1)
	Oil (Bbl)		$45.42			$38.69			$38.78			$43.67
	Natural gas liquids (Bbl)			19.33			13.86			15.32			14.04
	Natural gas (Mcf)			2.60			1.86			2.02			2.23
	Mcfe			3.25			2.45			2.59			2.74
	Average unit cost per Mcfe:
	Production costs:
	Lease operating expenses		$1.43			$1.54			$1.46			$1.56
	Production taxes			0.12			0.11			0.10			0.11
	Total			1.55			1.65			1.56			1.67
	Depreciation, depletion and amortization			1.73			1.62			1.69			1.66
	General and administrative expenses			0.55			0.52			0.48			0.62
	(1) Prior to $8.8 million and $44.9 million of net hedge gains on settlements of commodity derivatives for the three months ended December 30, 2016 and 2015, respectively, and $57.9 million and $143.3 million for the twelve months ended December 31, 2016 and 2015, respectively.

Consolidated Balance Sheets
(In $ thousands, except number of units)
		December 31, 2016				December 31, 2015
ASSETS
Current assets:
Cash and cash equivalents		$5,557				$20,415
Accounts receivable:
Oil, natural gas and natural gas liquids revenues			39,629				24,285
Related party			745				-
Other			2,451				7,137
Derivative asset			201				60,662
Other current assets			3,718				3,057
Total current assets			52,301				115,556
Oil and natural gas properties, net of accumulated
depreciation, depletion and amortization; December 31,
2016, $1,051,600; December 31, 2015, $971,499			1,497,211				1,790,455
Other property, net of accumulated depreciation
and amortization; December 31, 2016, $1,002;
December 31, 2015, $970			996				1,019
Restricted cash			52,076				-
Long–term derivative asset			-				10,741
Other assets			4,186				5,831
Total assets		$1,606,770				$1,923,602
LIABILITIES AND OWNERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities:
Third party		$31,700				$43,135
Related party			5,797				5,952
Derivative liability			21,679				-
Income taxes			-				11,657
Total current liabilities			59,176				60,744
Asset retirement obligations			180,241				174,003
Long–term debt, net			606,948				688,614
Long–term derivative liability			955				-
Other long–term liabilities			1,043				1,682
Commitments and contingencies
Owners’ equity:
Common unitholders - 49,055,214 units and
48,871,399 units issued and outstanding as of
December 31, 2016 and 2015, respectively			776,158				1,011,509
General partner interest			(17,751)				(12,950)
Total owners' equity			758,407				998,559
Total liabilities and owners' equity		$1,606,770				$1,923,602

Consolidated Statements of Operations
(In $ thousands, except per unit data)
		Three Months Ended December 31,								Twelve Months Ended December 31,
			2016				2015				2016				2015
Revenues:
Oil, natural gas and natural gas liquids revenues		$51,842				$47,354				$182,696				$175,088
Transportation and marketing–related revenues			599				598				2,198				2,883
Total revenues			52,441				47,952				184,894				177,971
Operating costs and expenses:
Lease operating expenses			22,839				29,793				103,371				99,626
Cost of purchased natural gas			421				400				1,497				1,988
Dry hole and exploration costs			(544)				1,975				651				3,695
Production taxes			1,885				2,076				7,386				6,784
Accretion expense on obligations			2,079				2,050				8,225				5,598
Depreciation, depletion and amortization			27,679				31,251				119,171				105,969
General and administrative expenses			8,775				10,026				33,637				38,994
Impairment of oil and natural gas properties			127,889				14,423				131,260				136,667
Impairment of goodwill			-				65,924				-				65,924
Loss (gain) on settlement of contract			-				1,210				(3,185)				1,210
Gain on sales of oil and natural gas properties			(69)				(20)				(69)				(551)
Total operating costs and expenses			190,954				159,108				401,944				465,904
Operating loss			(138,513)				(111,156)				(217,050)				(287,933)
Other income (expense), net:
Gain (loss) on derivatives, net			(18,758)				26,739				(35,950)				78,145
Interest expense			(9,933)				(12,057)				(42,487)				(50,336)
Gain on early extinguishment of debt			-				24,024				47,695				24,024
Other income, net			936				27				2,522				78
Total other income (expense), net			(27,755)				38,733				(28,220)				51,911
Income (loss) from continuing operations before income taxes			(166,268)				(72,423)				(245,270)				(236,022)
Income taxes			596				1,159				2,375				1,843
Income (loss) from continuing operations			(165,672)				(71,264)				(242,895)				(234,179)
Income from discontinued operations			-				-				-				255,512
Net income (loss)		$(165,672)				$(71,264)				$(242,895)				$21,333
Earnings per limited partner unit (basic and diluted):
Income (loss) from continuing operations		$(3.31)				$(1.43)				$(4.85)				$(4.72)
Income from discontinued operations			-				-				-				5.13
Net income (loss)		$(3.31)				$(1.43)				$(4.85)				$0.41
Weighted average limited partner units outstanding (basic and diluted)			49,055				48,871				49,048				48,853
Distributions declared per common unit		$     -				$0.075				$     -				$1.575

Consolidated Statements of Cash Flows
(In $ thousands)
		Twelve Months Ended December 31,
			2016				2015
Cash flows from operating activities:
Net income (loss)		$(242,895)				$21,333
Adjustments to reconcile net income (loss) to net cash flows provided by operating activities:
Income from discontinued operations			-				(255,512)
Amortization of volumetric production payment liability			(4,108)				(1,196)
Accretion expense on obligations			8,225				5,598
Depreciation, depletion and amortization			119,171				105,969
Equity–based compensation cost			6,611				12,001
Impairment of oil and natural gas properties			131,260				136,667
Impairment of goodwill			-				65,924
Gain on sales of oil and natural gas properties			(69)				(551)
Loss (gain) on derivatives, net			35,950				(78,145)
Cash settlements of matured derivative contracts			54,884				140,657
Gain on early extinguishment of debt			(47,695)				(24,024)
Deferred taxes			(404)				(13,285)
Other			2,523				4,487
Changes in operating assets and liabilities:
Accounts receivable			(11,403)				14,850
Other current assets			(361)				511
Accounts payable and accrued liabilities			(5,862)				(4,067)
Income taxes			(11,657)				10,683
Other, net			(295)				(245)
Net cash flows provided by operating activities from continuing operations			33,875				141,655
Net cash flows used in operating activities from discontinued operations			-				(372)
Net cash flows provided by operating activities			33,875				141,283
Cash flows from investing activities:
Acquisitions of oil and natural gas properties, net of cash acquired			-				(250,357)
Additions to oil and natural gas properties			(15,258)				(67,923)
Proceeds from sales of oil and natural gas properties			54,509				1,457
Restricted cash			(52,076)				33,768
Cash settlements from acquired derivative contracts			3,003				2,615
Other			56				73
Net cash flows used in investing activities from continuing operations			(9,766)				(280,367)
Net cash flows provided by investing activities from discontinued operations			-				572,160
Net cash flows (used in) provided by investing activities			(9,766)				291,793
Cash flows from financing activities:
Long-term debt borrowings			57,000				295,000
Repayments of long-term debt borrowings			(57,000)				(561,000)
Redemption of 8% Senior Notes due 2019			(34,978)				(49,954)
Loan costs paid			(121)				(4,074)
Contributions from general partner			-				91
Distributions paid			(3,868)				(100,979)
Net cash flows used in financing activities			(38,967)				(420,916)
(Decrease) increase in cash and cash equivalents			(14,858)				12,160
Cash and cash equivalents – beginning of period			20,415				8,255
Cash and cash equivalents – end of period		$5,557				$20,415

Non GAAP Measures

We define Adjusted EBITDAX as net income (loss) plus income from discontinued operations, EBITDAX from discontinued operations, income taxes, interest expense, net, cash settlements of matured interest rate swaps, depreciation, depletion and amortization, accretion expense on obligations, amortization of volumetric production payment (VPP), loss (gain) on derivatives, net, cash settlements of matured derivative contracts, non-cash equity-based compensation, impairment of oil and natural gas properties, impairment of goodwill, non-cash inventory write down expense, dry hole and exploration costs, gain on sales of oil and natural gas properties, loss (gain) on settlement of contract, gain on early extinguishment of debt, and (gain) loss on sale of investment, contained in Other income, net. Distributable Cash Flow is defined as Adjusted EBITDAX less cash income taxes, cash interest expense, net, realized losses on interest rate swaps, and estimated maintenance capital expenditures.

Adjusted EBITDAX and Distributable Cash Flow are used by our management to provide additional information and statistics relative to the performance of our business, including (prior to the creation of any reserves) the cash available to pay distributions to our unitholders. We believe these financial measures may indicate to investors whether or not we are generating cash flow at a level that can sustain or support 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 Income (Loss) to Adjusted EBITDAX and Distributable Cash Flow
(In $ thousands)
		Three Months Ended												Twelve Months Ended
		Dec 31, 2016				Dec 31, 2015				Sep 30, 2016				Dec 31, 2016				Dec 31, 2015
Net income (loss)		$(165,672)				$(71,264)				$(19,230)				$(242,895)				$21,333
Add:
Income from discontinued operations			-				-				-				-				(255,512)
EBITDAX from discontinued operations			-				-				-				-				15,941
Income taxes			(596)				(1,159)				(1,429)				(2,375)				(1,843)
Interest expense, net			9,932				12,050				9,889				42,476				50,314
Cash settlements of matured interest rate swaps			-				-				-				-				1,736
Depreciation, depletion and amortization			27,679				31,251				31,639				119,171				105,969
Accretion expense on obligations			2,079				2,050				2,057				8,225				5,598
Amortization of VPP			(1,038)				(1,196)				(1,027)				(4,108)				(1,196)
Loss (gain) on derivatives, net			18,758				(26,739)				(8,559)				35,950				(78,145)
Cash settlements of matured derivative contracts			8,765				44,904				10,117				57,887				143,272
Non-cash equity-based compensation			1,758				2,366				1,889				6,611				12,001
Impairment of oil and natural gas properties			127,889				14,423				687				131,260				136,667
Impairment of goodwill			-				65,924				-				-				65,924
Non-cash inventory write down expense			(422)				973				-				(299)				1,122
Dry hole and exploration costs			(544)				1,975				294				651				3,695
Gain on sales of oil and natural gas properties			(69)				(20)				-				(69)				(551)
Loss (gain) on settlement of contract			-				1,210				-				(3,185)				1,210
Gain on early extinguishment of debt			-				(24,024)				-				(47,695)				(24,024)
(Gain) loss on sale of investment, contained in Other income, net			-				-				(309)				(309)				358
Adjusted EBITDAX		$28,519				$52,724				$26,018				$101,296				$203,869
Less:
Cash income taxes			-				441				(933)				(933)				441
Cash interest expense, net			9,609				11,264				9,566				39,558				48,504
Realized losses on interest rate swaps			-				-				-				-				1,736
Estimated maintenance capital expenditures (1)			11,000				14,875				11,000				44,000				54,672
Distributable Cash Flow		$7,910				$26,144				$6,385				$18,671				$98,516
(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.

Total Current Hedge Position

		Swap	Swap			Collar	Collar		Collar
Period	Index	Volume	Price			Volume	Floor		Ceiling
Natural Gas (Mmmbtus)
2017	NYMEX	32,850	$3.07			10,950	$2.75		$3.27
Jan - Mar 2018	NYMEX	4,500	$3.46
Crude (Mbbls)
2017	WTI	365	$52.85
Ethane (Mbbls)
2017	Mt Belvieu	511.0	$11.66
Propane (Mbbls)
2017	Mt Belvieu	255.5	$25.10
		Notional Amount		Fixed Rate
Interest Rate Swap Agreements		($ mill)
Jan 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