EV Energy Partners Announces Fourth Quarter and Full Year 2013 Results, Year-end Proved Reserves, 2014 Guidance and Updated Hedge Positions

HOUSTON, March 3, 2014 /PRNewswire/ -- EV Energy Partners, L.P. (NASDAQ: EVEP) today announced results for the fourth quarter and full year 2013 and the filing of its Form 10-K with the Securities and Exchange Commission.  In addition, EVEP announced its 2013 year-end proved reserves, 2014 guidance and an update of its commodity hedge positions.

2013 Highlights

• Overall operating results were in line with expectations
• Attractive proved reserve growth and reserve replacement rates and replacement costs
  • Proved reserves increased 32 percent
  • Price neutral reserve replacement cost of $1.01/Mcfe
• Significant Utica midstream investment with initial start-up of operations
  • 400 MMcf/day of processing and 45,000 Bbls/day of fractionation capacity now online
  • Start-up of additional 400 MMcf/day of processing and 90,000 Bbls/day of fractionation capacity expected in the second and third quarters of 2014
• Completion of initial Utica acreage sales

Full Year 2013 Results

Adjusted EBITDAX and Distributable Cash Flow for 2013 of $209.0 million and $100.6 million, decreased 22 percent and 29 percent, respectively, versus 2012.  The decreases in Adjusted EBITDAX and Distributable Cash Flow as compared to year-end 2012, which are described in the attached table under "Non-GAAP Measures," are primarily attributable to the decrease in cash settlements on commodity derivatives, partially offset by an increase in the sales price per unit of natural gas.

Production for 2013 was 42.7 Bcf of natural gas, 1,027 MBbls of oil and 2,146 MBbls of natural gas liquids, or 169.0 million cubic feet equivalent per day (MMcfe/day).  This represents a 3 percent increase over year-end 2012 production of 163.4 MMcfe/day, primarily due to 2013 drilling activity and acquisitions completed during the fourth quarter of 2013.

For 2013, EVEP reported a net loss of $76.2 million, or $(1.76) per basic and diluted weighted average limited partner unit outstanding.  Included in net loss were the following items:

• $85.3 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,
• $47.3 million of non-cash losses on commodity and interest rate derivatives,
• $41.3 million gain on the sale of oil and natural gas properties,
• $17.5 million of non-cash costs contained in general and administrative expenses, and
• $2.4 million of dry hole and exploration costs.

For 2012, EVEP reported a net loss of $16.3 million, or $(0.38) per basic and diluted weighted average limited partner unit outstanding. 

Fourth Quarter 2013 Results

Adjusted EBITDAX for the fourth quarter of 2013 was $53.7 million, a 23 percent decrease from the fourth quarter of 2012, primarily attributable the decrease in cash settlements on commodity derivatives, and flat compared to the third quarter of 2013.  Distributable Cash Flow for the fourth quarter of 2013 was $26.7 million, a 30 percent decrease from the fourth quarter of 2012 and a 3 percent increase over the third quarter of 2013.

Production for the fourth quarter of 2013 was 10.8 Bcf of natural gas, 240 MBbls of oil and 580 MBbls of natural gas liquids, or 170.5 MMcfe/day. This represents a 3 percent increase over fourth quarter 2012 production of 166.3 MMcfe/d and a 2 percent increase over third quarter 2013 production of 168.0 MMcfe/day.  The increases in production are primarily due to 2013 drilling activity and acquisitions completed during the fourth quarter of 2013, partially offset by the effect of fourth quarter 2013 weather. 

EVEP reported a net loss of $50.2 million, or $(1.06) per basic and diluted weighted average limited partner unit outstanding, for the fourth quarter of 2013. Included in net loss were the following items:

• $77.2 million of impairment charges primarily related to the write-down of Permian Basin oil and natural gas properties due to the effects of commodity prices on expected future net cash flows,
• $41.3 million gain on the sale of oil and natural gas properties,
• $21.2 million of non-cash losses on commodity and interest rate derivatives, and
• $4.4 million of non-cash costs contained in general and administrative expenses.

For the third quarter of 2013, EVEP reported a net loss of $12.3 million, or $(0.29) per basic and diluted weighted average limited partner unit outstanding.  For the fourth quarter of 2012, EVEP reported a net loss of $9.9 million, or $(0.23) per basic and diluted weighted average limited partner unit outstanding.

Year-end 2013 Estimated Net Proved Reserves

EVEP's year-end 2013 estimated net proved reserves were 1,192 Bcfe, a 32 percent increase over year-end 2012 estimated net proved reserves.  Approximately 69 percent of these reserves were natural gas, 25 percent were natural gas liquids and 6 percent were oil.  In addition, 68 percent were categorized as proved developed.

At December 31, 2013, the present value of future net pre-tax cash flows discounted at 10 percent was $1,049 million and the standardized measure of estimated net proved reserves was $1,040 million. Standardized measure includes future obligations under the Texas gross margin tax, but it does not include future federal income tax expenses because EVEP is a partnership and is not subject to federal income taxes. The prices used in determining estimated net proved reserves at December 31, 2013 were $96.78 per Bbl of oil and $3.67 per MMBtu of natural gas as compared to$94.71 per Bbl of oil and $2.76 per MMBtu of natural gas at December 31, 2012. 

		Estimated Net Proved Reserves
		Oil (MMBbls)		Natural Gas (Bcf)		Natural Gas Liquids (MMBbls)		Bcfe
Barnett Shale		1.7		529.6		40.2		781.5
Appalachian Basin		4.8		80.0		0.4		111.1
Mid-Continent area		2.6		44.1		1.0		65.4
Monroe Field		-		56.2		-		56.2
Central and East Texas		2.6		24.7		2.0		52.2
San Juan Basin		0.9		31.7		2.2		50.1
Michigan		-		40.6		0.0		40.7
Permian Basin		0.5		12.8		3.1		34.4
Total		13.1		819.7		48.9		1,191.6

The reserve replacement rate for 2013 was 565 percent at a cost of $0.48 per Mcfe. As detailed above, the prices used in determining year-end 2013 estimated proved reserves were higher than those used at year-end 2012. Without these positive price revision effects, the reserve replacement rate would have been 268 percent at a cost of $1.01 per Mcfe including acquisitions, and 156 percent at a cost of $1.06 per Mcfe excluding acquisitions.

"For 2013, we are very pleased with our operational performance, even with some small short term oil and gas production and midstream throughput disruptions due to the cold weather this winter. We had strong growth in proved reserves through our capital programs, and we continue to see potential growth opportunities in the Barnett Shale and the Eagle Ford Shale within our existing assets.  We also are pleased with the evolution of theUtica Shale and our participation in both upstream and midstream activities.  We expect significant  growth in our Utica midstream cash flow as these facilities continue to come on line," said Mark Houser, President and CEO.

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

EVEP's financial statements and related footnotes are available on our 2013 Form 10-K, which was filed today and is available through the Investor Relations/SEC Filings section of the EVEP website at http://www.evenergypartners.com.

Also available for download on our website after March 7, 2014 will be unitholders' Schedule K-1's for the tax year 2013.  For any questions regarding their Schedule K-1, unitholders are invited to call the Tax Package Support helpline at 1-800-973-7551.

Conference Call

As announced on February 20, 2014, EV Energy Partners, L.P. will host an investor conference call on March 3, 2014, at 9 a.m. Eastern Standard Time(8 a.m. Central).  Investors interested in participating in the call may dial (877) 941-8609 (quote conference ID 4670286) 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. 

As previously announced, Mark Houser, President and CEO, and Michael Mercer, Senior Vice President and CFO, will be presenting at the Raymond James 35^th Annual Institutional Investor Conference in Orlando, Florida today, March 3, 2014 at 2:15 p.m. Eastern Standard Time. The presentation slides will be available on our website in the Investor Relations section under Presentation & Event Schedule.

EV Energy Partners, L.P. is a master limited partnership engaged in acquiring, producing and developing oil and gas properties.  More information about EVEP is available on the Internet at http://www.evenergypartners.com.

(code #: EVEP/G)

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 assets, our midstream investments, future plans, our reserve quantities and the present value of our reserves, estimates of maintenance capital and other statements which include words such as "anticipates," "plans," "projects," "expects," "intends," "believes," "should," and similar expressions of forward-looking information. Forward-looking statements are inherently uncertain and necessarily involve risks that may affect the business prospects and performance of EV Energy Partners, L.P. Actual results may differ materially from those contained in the press release. Such risks and uncertainties include, but are not limited to, changes in commodity prices, changes in reserve estimates, requirements and actions of purchasers of properties (including the Utica Shale), changes in the metrics and procedures used to value midstream assets, exploration and development activities in the Utica Shale and elsewhere, the availability and cost of financing, the returns on our capital investments and acquisition strategies, the availability of sufficient cash flow to pay distributions and execute our business plan and general economic conditions. Additional information on risks and uncertainties that could affect our business prospects and performance are provided in the most recent reports of EV Energy Partners with the Securities and Exchange Commission. All forward-looking statements included in this press release are expressly qualified in their entirety by the foregoing cautionary statements.

Any forward-looking statement speaks only as of the date on which such statement is made and EVEP undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise.

2014 Guidance
($ in Millions)
		1st Qtr 2014				2nd - 4th Qtr 2014				Full Year 2014
Net Production:
Natural Gas (MMcf)		10,500	-	10,900		31,500	-	34,400		42,000	-	45,300
Crude Oil (MBbls)		250	-	260		770	-	840		1,020	-	1,100
Natural Gas Liquids (MBbls)		550	-	560		1,720	-	1,880		2,270	-	2,440
Total Mmcfe		15,300	-	15,820		46,440	-	50,720		61,740	-	66,540
Average Daily Production (MMcfe/d)		170.0	-	175.8		168.9	-	184.4		169.2	-	182.3
Average Price Differential vs NYMEX
Natural Gas (% of NYMEX Natural Gas)		90%	-	94%		90%	-	94%		90%	-	94%
Crude Oil (% of NYMEX Crude Oil)		94%	-	99%		94%	-	99%		94%	-	99%
Transportation Margin (a)		$0.2	-	$0.4		$0.7	-	$1.1		$0.9	-	$1.5
Expenses:
Operating Expenses:
LOE and other		$25.0	-	$27.0		$77.0	-	$85.0		$102.0	-	$112.0
Production Taxes (as % of revenue)		3.5%	-	4.0%		3.5%	-	4.0%		3.5%	-	4.0%
General and administrative expense (b)		$6.5	-	$8.5		$15.0	-	$18.0		$21.5	-	$26.5
Utica Shale Midstream and ORRI EBITDAX (c)		$3.0	-	$4.5		$30.5	-	$35.5		$33.5	-	$40.0
E&P Capital Expenditures (d)		$19.0	-	$25.0		$76.0	-	$90.0		$95.0	-	$115.0
Midstream Investment		$40.0	-	$46.0		$75.0	-	$89.0		$115.0	-	$135.0

(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)	Quarterly Utica Shale Midstream and ORRI EBITDAX guidance is $7.5 - $10.0 million for 2Q14, $10.0 - $13.0 million for 3Q14, and $11.0 - $14.0 million for 4Q14.
(d)	Represents estimates for drilling and related capital expenditures.  Does not include any amounts for acquisitions of oil and gas properties.

 

Operating Statistics
		Three Months Ended December 31,				Twelve Months Ended December 31,
		2013		2012		2013		2012
Production data:
Oil (MBbls)		240		277		1,027		1,110
Natural gas liquids (MBbls)		580		476		2,146		1,742
Natural gas (MMcf)		10,772		10,779		42,651		42,536
Net production (MMcfe)		15,690		15,298		61,690		59,647
Average sales price per unit: (1)
Oil (Bbl)		$ 93.52		$ 86.83		$ 95.62		$ 91.94
Natural gas liquids (Bbl)		33.22		31.72		30.86		36.02
Natural gas (Mcf)		3.33		3.27		3.43		2.75
Mcfe		4.94		4.86		5.04		4.72
Average unit cost per Mcfe:
Production costs:
Lease operating expenses (2)		$ 1.66		$ 1.66		$ 1.69		$ 1.74
Production taxes		0.17		0.16		0.19		0.18
Total		1.83		1.82		1.88		1.92
Asset retirement obligations accretion expense		0.08		0.09		0.08		0.09
Depreciation, depletion and amortization		1.75		2.11		1.85		1.90
General and administrative expenses		0.64		0.66		0.66		0.72

(1) Prior to $9.2 million and $28.4 million of net hedge gains and settlements on commodity derivatives for the three months ended December 31, 2013 and December 31, 2012, respectively, and $33.5 million and $123.0 million for the twelve months ended December 31, 2013 and December 31, 2012, respectively.

(2) Lease operating expenses for the twelve months ended December 31, 2012 contains $1.7 million ($0.03 per Mcfe) of non-cash charges related to oil in tanks purchased in connection with 2011 acquisitions.

 

Consolidated Balance Sheets
(In $ thousands, except number of units)
		December 31, 2013		December 31, 2012
ASSETS
Current assets:
Cash and cash equivalents		$ 11,698		$ 7,486
Accounts receivable:
Oil, natural gas and natural gas liquids revenues		37,661		34,909
Related party		2,873		1,422
Other		1,111		11,263
Derivative asset		13,543		40,771
Other current assets		6,916		1,750
Assets held for sale		8,012		-
Total current assets		81,814		97,601
Oil and natural gas properties, net of accumulated
depreciation, depletion and amortization; December 31,
2013, $569,770; December 31, 2012, $389,206		1,829,062		1,875,890
Other property, net of accumulated depreciation
and amortization; December 31, 2013, $754;
December 31, 2012, $598		1,259		1,325
Long-term derivative asset		29,088		45,839
Investments in unconsolidated affiliates		254,978		34,545
Other assets		8,782		10,214
Total assets		$ 2,204,983		$ 2,065,414
LIABILITIES AND OWNERS' EQUITY
Current liabilities:
Accounts payable and accrued liabilities		$ 46,876		$ 40,171
Derivative liability		3,348		-
Liabilities related to assets held for sale		2,155		-
Total current liabilities		52,379		40,171
Asset retirement obligations		99,133		102,707
Long-term debt		980,297		859,218
Other long-term liabilities		1,241		3,494
Commitments and contingencies
Owners' equity:
Common unitholders - 48,349,080 units and
42,320,707 units issued and outstanding as of
December 31, 2013 and December 31, 2012,
respectively		1,083,718		1,072,175
General partner interest		(11,785)		(12,351)
Total owners' equity		1,071,933		1,059,824
Total liabilities and owners' equity		$ 2,204,983		$ 2,065,414

Consolidated Statements of Operations
(In $ thousands, except per unit data)
		Three Months Ended December 31,				Twelve Months Ended December 31,
		2013		2012		2013		2012
Revenues:
Oil, natural gas and natural gas liquids revenues		$ 77,558		$ 74,408		$ 310,883		$ 281,749
Transportation and marketing-related revenues		1,036		1,088		4,429		3,731
Total revenues		78,594		75,496		315,312		285,480
Operating costs and expenses:
Lease operating expenses		25,969		25,334		104,465		103,605
Cost of purchased natural gas		756		792		3,242		2,600
Dry hole and exploration costs		(89)		1,107		2,380		6,771
Production taxes		2,725		2,517		11,476		10,911
Asset retirement obligations accretion expense		1,181		1,353		4,925		5,116
Depreciation, depletion and amortization		27,379		32,254		113,818		113,381
General and administrative expenses		10,006		10,120		40,677		42,682
Impairment of oil and natural gas properties		77,200		16,701		85,341		34,453
Gain on sales of oil and natural gas properties		(41,309)		-		(41,309)		-
Total operating costs and expenses		103,818		90,178		325,015		319,519
Operating loss		(25,224)		(14,682)		(9,703)		(34,039)
Other (expense) income, net:
(Loss) gain on derivatives, net		(12,848)		16,778		(17,262)		66,734
Interest expense		(11,771)		(12,202)		(49,062)		(48,689)
Other income, net		45		323		277		705
Total other (expense) income, net		(24,574)		4,899		(66,047)		18,750
Loss before income taxes and equity in (loss) income of unconsolidated affiliates		(49,798)		(9,783)		(75,750)		(15,289)
Income taxes		193		(174)		(133)		(1,078)
Loss before equity in (loss) income of unconsolidated affiliates		(49,605)		(9,957)		(75,883)		(16,367)
Equity in (loss) income of unconsolidated affiliates		(581)		78		(344)		18
Net loss		($ 50,186)		($ 9,879)		($ 76,227)		($ 16,349)
Net loss per limited partner unit:
Basic		($ 1.06)		($ 0.23)		($ 1.76)		($ 0.38)
Diluted		($ 1.06)		($ 0.23)		($ 1.76)		($ 0.38)
Weighted average limited partner units outstanding:
Basic		46,974		42,452		43,691		41,952
Diluted		46,974		42,452		43,691		41,952
Distributions declared per unit		$ 0.771		$ 0.767		$ 3.078		$ 3.062

Consolidated Statements of Cash Flows
(In $ thousands)
		Twelve Months Ended December 31,
		2013		2012
Cash flows from operating activities:
Net loss		($ 76,227)		($ 16,349)
Adjustments to reconcile net loss to net cash flows provided by operating activities:
Dry Hole Costs		616		1,100
Asset retirement obligations accretion expense		4,925		5,116
Depreciation, depletion and amortization		113,818		113,381
Equity-based compensation		17,470		16,433
Impairment of oil and natural gas properties		85,341		34,453
Gain on sales of oil and natural gas properties		(41,309)		-
Loss (gain) on derivatives, net		17,262		(66,734)
Cash settlements of matured derivative contracts		30,066		114,343
Amortization of deferred loan costs		2,333		2,183
Equity in loss (income) of unconsolidated affiliates		344		(18)
Distributions from unconsolidated affiliates		285		79
Other		(296)		2,165
Changes in operating assets and liabilities:
Accounts receivable		(2,671)		(1,773)
Other current assets		(68)		51
Accounts payable and accrued liabilities		1,316		5,185
Other, net		(706)		(100)
Net cash flows provided by operating activities		152,499		209,515
Cash flows from investing activities:
Acquisitions of oil and natural gas properties		(57,976)		(120,033)
Additions to oil and natural gas properties		(97,946)		(129,783)
Prepaid drilling costs		(5,041)		-
Investments in unconsolidated affiliates		(221,101)		(33,811)
Proceeds from sales of oil and natural gas properties		44,056		5,522
Distributions from unconsolidated affiliates		38		19
Settlements from acquired derivatives		-		4,578
Net cash flows used in investing activities		(337,970)		(273,508)
Cash flows from financing activities:
Long-term debt borrowings		329,000		160,000
Repayments of long-term debt borrowings		(208,000)		(460,000)
Proceeds from debt offering		-		206,000
Loan costs paid		-		(4,152)
Proceeds from public equity offerings		204,527		262,833
Offering costs		(226)		(304)
Contributions from general partner		4,508		5,714
Distributions paid		(140,126)		(128,924)
Net cash flows provided by financing activities		189,683		41,167
Increase (decrease) in cash and cash equivalents		4,212		(22,826)
Cash and cash equivalents - beginning of period		7,486		30,312
Cash and cash equivalents - end of period		$ 11,698		$ 7,486

Non GAAP Measures

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

Reconciliation of Net Income to Adjusted EBITDAX and Distributable Cash Flow
(In $ thousands)
		Three Months Ended December 31,				Twelve Months Ended December 31,
		2013		2012		2013		2012
Net loss		($ 50,186)		($ 9,879)		($ 76,227)		($ 16,349)
Add:
Equity in loss (income) from unconsolidated affiliates		581		(78)		344		(18)
EBITDAX from unconsolidated affiliates		974		-		2,264		-
Income taxes		(193)		174		133		1,078
Interest expense, net		11,769		12,199		49,057		48,668
Cash settlements of matured interest rate swaps		874		860		3,476		4,032
Depreciation, depletion and amortization		27,379		32,254		113,818		113,381
Asset retirement obligations accretion expense		1,181		1,353		4,925		5,116
Loss (gain) on derivatives, net		12,848		(16,778)		17,262		(66,734)
Cash settlements of matured derivative contracts		8,317		27,575		30,066		118,920
Non-cash equity compensation expense		4,391		4,043		17,470		16,433
Impairment of oil and natural gas properties		77,200		16,701		85,341		34,453
Non-cash inventory write down expense		-		-		-		1,729
Dry hole and exploration costs		(89)		1,107		2,380		6,771
Gain on sales of oil and natural gas properties		(41,309)		-		(41,309)		-
Adjusted EBITDAX		$ 53,737		$ 69,531		$ 209,001		$ 267,480
Less:
Cash income taxes		155		79		203		243
Cash interest expense, net		11,164		11,599		46,646		46,289
Realized losses on interest rate swaps		874		860		3,476		4,032
Estimated maintenance capital expenditures (1)		14,850		19,123		58,047		74,559
Distributable Cash Flow		$ 26,694		$ 37,870		$ 100,629		$ 142,357

(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.

 

Summary of New Hedge Positions (since November 12, 2013)
Period	Index	Swap Volume	Swap Price
Natural Gas		(Mmmbtu/Mbbls)
2014	NYMEX	4,745.0	$4.10
2015	NYMEX	4,745.0	$4.10
2016	NYMEX	10,980.0	$4.17
Hedge Summary Table (as of February 28, 2014)
		Swap	Swap
Period	Index	Volume	Price
Natural Gas		(Mmmbtu/Mbbls)
1Q 2014	NYMEX	9,792.0	$4.72
2Q 2014	NYMEX	9,900.8	$4.72
3Q 2014	NYMEX	10,009.6	$4.70
4Q 2014	NYMEX	10,009.6	$4.66
2015	NYMEX	36,317.5	$4.94
2016	NYMEX	10,980.0	$4.17
Crude
1Q 2014	WTI	378.0	$89.78
2Q 2014	WTI	382.2	$89.78
3Q 2014	WTI	380.3	$91.50
4Q 2014	WTI	377.2	$93.73
2015	WTI	730.0	$90.09
Interest Rate Swap Agreements		Notional Amount	Fixed Rate
		(in $ mill)
January 2014 - July 2015		110	3.315%

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