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EV Energy Partners Announces Fourth Quarter and Full Year 2016 Results, Additional Commodity Hedges, Year-end Proved Reserves and 2017 Guidance

HOUSTON, March 01, 2017 (GLOBE NEWSWIRE) -- 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 area1.1 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
PeriodIndex Volume Price
Volume Floor Ceiling
Natural Gas (Mmmbtus)
2017NYMEX32,850$3.07 10,950$2.75$3.27
Jan - Mar 2018NYMEX4,500$3.46
Crude (Mbbls)
2017WTI365$52.85
Ethane (Mbbls)
2017Mt Belvieu511.0$11.66
Propane (Mbbls)
2017Mt Belvieu255.5$25.10
Notional Amount Fixed Rate
Interest Rate Swap Agreements ($ 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

Source:EV Energy Partners, L.P.