Harvest Oil & Gas Corp. - Annual Report: 2016 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K

For the fiscal year ended December 31, 2016

OR

Commission File Number

001-33024

EV Energy Partners, L.P.

(Exact name of registrant as specified in its charter)

Registrant’s telephone number, including area code: (713) 651-1144

Securities registered pursuant to Section 12(b) of the Act:

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES þ NO ¨

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES ¨ NO þ

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. YES þ NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). YES þ NO o

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III or any amendment to the Form 10–K. þ

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b–2 of the Exchange Act. Check one:

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b–2 of the Exchange Act).

YES ¨ NO þ

The aggregate market value of the common units held by non–affiliates at June 30, 2016 based on the closing price on the NASDAQ Global Market on June 30, 2016 was $100,811,559.

As of February 15, 2017, the registrant had 49,368,869 common units outstanding.

Table of Contents

GLOSSARY OF OIL AND NATURAL GAS TERMS

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume of oil or other liquid hydrocarbons.

Bcf. One billion cubic feet of natural gas.

Bcfe. One billion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed oil and gas reserves. Reserves of any category that can be expected to be recovered:

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or well. An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

Exploration costs. Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

Mcf. One thousand cubic feet of natural gas.

Mcfe. One thousand cubic feet of natural gas equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids.

MMBbls. One million barrels of oil or other liquid hydrocarbons.

MMBtu. One million British thermal units.

MMcf. One million cubic feet of natural gas.

MMcfe. One million cubic feet equivalent, determined using the ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Natural gas liquids. The hydrocarbon liquids contained within natural gas.

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

NYMEX. The New York Mercantile Exchange.

Oil. Crude oil and condensate.

Overriding royalty interest (“ORRI”). Fractional, undivided interests or rights of participation in the oil and natural gas, or in the proceeds from the sale of oil and natural gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

Productive well. An exploratory, development or extension well that is not a dry well.

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

Proved undeveloped reserves (“PUDs”). Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for proved undeveloped reserves are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized measure. 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%. Our standardized measure includes 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.

Tcfe. One trillion cubic feet equivalent, determined using a ratio of six Mcf of natural gas to one Bbl of oil, condensate or natural gas liquids.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

Undeveloped oil and gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

Workover. Operations on a producing well to restore or increase production.

PART I

ITEM 1. BUSINESS

Overview

EV Energy Partners, L.P. (“we,” “our,” “us” or the “Partnership”) is a publicly held Delaware limited partnership formed in 2006. Our general partner is EV Energy GP, L.P. (“EV Energy GP”), a Delaware limited partnership, and the general partner of our general partner is EV Management, LLC (“EV Management”), a Delaware limited liability company. EV Management is a wholly owned subsidiary of EnerVest, Ltd. (“EnerVest”), a Texas limited partnership. EnerVest and its affiliates have a significant interest in us through their 71.25% ownership of EV Energy GP which, in turn, owns a 2% general partner interest in us and all of our incentive distribution rights (“IDRs”).

Our common units are traded on the NASDAQ Global Market under the symbol “EVEP.” Our business activities are primarily conducted through wholly owned subsidiaries.

As of December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin.

Oil, natural gas and natural gas liquids reserve information is derived from our reserve reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) and Wright & Company, Inc. (“Wright”), our independent reserve engineers. All of our proved reserves are located in the United States. The following table summarizes information about our proved reserves by geographic region as of December 31, 2016:

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The table below provides a reconciliation of PV–10 to the standardized measure at December 31, 2016 (dollars in millions):

Current Developments

Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and the beginning of 2017, they have continued to fluctuate.

Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow the market for oil.

In 2016, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.

In 2016, in response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:

As a result of the steps above, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:

During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than previous years. The board of directors continues to evaluate the distribution on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution in compliance with the covenants in our credit agreement. In order to reinstate distributions, we must be in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors - Covenants in our credit agreement may restrict our ability to resume and sustain distributions.

In December 2016, we sold a portion of our Barnett Shale natural gas properties for $52.1 million (before post-closing adjustments), which proceeds were deposited with a qualified intermediary to facilitate a like-kind exchange transaction pursuant to Section 1031 of the Internal Revenue Code. On January 31, 2017, we acquired a 5.8% working interest in 9,151 gross acres (529 net acres) in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the proceeds and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.

Long–Term Business Strategy

One of our primary business objectives is to manage our oil and natural gas properties for the purpose of generating sufficient excess cash flow that will allow us to reinstate a stable distribution, which we will be able to grow over time. To meet this objective, we intend to execute the following business strategies:

We seek to maintain an inventory of drilling and development projects to maintain and grow our production from our capital development program. EnerVest operates properties representing approximately 94% of our estimated net proved reserves as of December 31, 2016. Our development program is focused on lower–risk, repeatable drilling opportunities to maintain and grow cash flow.

We focus on controlling the operating costs of our properties. We manage our operating costs by using advanced technologies and integrating the knowledge, expertise and experience of our management teams as well as the managerial and technical staff of EnerVest. Regarding our non–operated properties, we proactively engage with the operators to ensure disciplined and cost focused operations are being implemented.

Since our initial public offering in 2006, we have financed approximately 52% of our $2.3 billion of acquisitions with free cash flow and the issuance of common units in public and private offerings. We seek to maintain sufficient liquidity not only for our operating positions but also to maintain flexibility in financing our acquisitions.

We continue to pursue a range of alternatives to optimize the value of our assets, and we cannot at this time predict the type of transaction or transactions into which we may enter. We may not be successful in our efforts or it may take longer to complete a transaction than we expect.

Our acquisition program targets oil and natural gas properties that we believe will generate attractive risk-adjusted expected rates of return and that will be financially accretive. These acquisitions are characterized by long–lived production, relatively low decline rates and predictable production profiles, as well as low–risk development opportunities. As part of this strategy, we continually seek to optimize our asset portfolio, which may include the divestiture of noncore assets.

Our acquisition efforts may involve our participation in auction processes, as well as situations in which we are the only party or one of a very limited number of potential buyers in negotiations with the potential seller. We finance acquisitions with a combination of cash flow from operations, borrowings under our credit facility and funds from equity and debt offerings. We also acquire interests in properties alongside the institutional partnerships managed by EnerVest, which has allowed us to participate in much larger acquisitions than would otherwise be available to us, and directly from institutional partnerships managed by EnerVest.

Changes in oil, natural gas and natural gas liquids prices may cause our revenues and cash flows to be volatile. We enter into various derivative contracts intended to achieve more predictable cash flow and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids. We currently maintain derivative contracts for a portion of our oil and natural gas production.

Our commodity derivatives are primarily in the form of swaps that are designed to provide a fixed price that we will receive. Without the use of these commodity derivatives, we would be exposed to the full range of price fluctuations. In addition, we enter into interest rate swaps to minimize the effects of fluctuations in interest rates.

Competitive Strengths

We believe that we are well positioned to achieve our primary business objectives and to execute our strategies because of the following competitive strengths:

Our properties are located in eight producing basins with an average reserve life of 15.3 years as of December 31, 2016. The majority of our properties have been producing for many years, resulting in predictable decline rates.

We have a significant inventory of development projects in our core areas of operation. At December 31, 2016, we had 3,014 identified gross drilling locations, of which approximately 144 were proved undeveloped drilling locations and the remainder were unproved drilling locations. In 2016, we drilled a total of 9 gross (2.6 net) development wells with a 100% gross success rate. Our development program is focused on lower risk drilling opportunities to maintain and increase production.

Our relationship with EnerVest provides us with a wide breadth of operational, financial, technical, risk management and other expertise across a broad geographical range, which assists us in evaluating acquisition and development opportunities. In addition, we believe that our relationship with EnerVest allows us to participate in much larger acquisitions that would not otherwise be available to us.

Our executive officers and key employees have on average over 25 years of experience in the oil and natural gas industry and over ten years of experience acquiring and managing oil and natural gas properties for EnerVest partnerships.

Our Relationship with EnerVest

Our general partner is EV Energy GP, and its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through our omnibus agreement, EnerVest agrees to make available its personnel to permit us to carry on our business. We therefore benefit from the technical expertise of EnerVest, which we believe would generally not otherwise be available to a company of our size.

EnerVest’s principal business is to act as general partner or manager of EnerVest partnerships, formed to acquire, explore, develop and produce oil and natural gas properties. A primary investment objective of the EnerVest partnerships is to make periodic cash distributions. EnerVest was formed in 1992 and is one of the 25 largest oil and natural gas companies in the United States, with more than 40,000 wells across 15 states, 6.5 million acres under lease and 5.4 Tcfe of proved reserves under management.

While our relationship with EnerVest is a significant attribute, it is also a source of potential conflicts. For example, we have acquired oil and natural gas properties from partnerships formed by EnerVest and partnerships in which EnerVest has an interest, and we may do so in the future. We have also acquired interests in oil and natural gas properties in conjunction with institutional partnerships managed by EnerVest. In these acquisitions, we and the institutional partnerships managed by EnerVest each acquire an interest in all of the properties subject to the acquisition. The purchase is allocated among us and the institutional partnerships managed by EnerVest based on the interest acquired. In the future, it is possible that we would vary the manner in which we jointly acquire oil and natural gas properties with the institutional partnerships managed by EnerVest.

EnerVest currently operates oil and natural gas properties representing 94% of our proved oil and gas reserves as of December 31, 2016. The EnerVest partnerships own interests in oil and gas properties in which we own interests. The properties are primarily located in the Barnett Shale, Central Texas and the Appalachian Basin, and these properties represent approximately 65% of our net proved reserves at December 31, 2016. The investment strategy of the EnerVest partnerships is to typically divest their properties in three to five years, while our strategy contemplates holding such properties for a longer term. If the EnerVest partnerships were to sell their interests in these properties to an entity not affiliated with EnerVest, we may not have a sufficient working interest to cause EnerVest to remain operator of the property. The EnerVest partnerships are under no obligation to us with respect to their sale of the properties they own.

EnerVest is not restricted from competing with us. It may acquire, develop or dispose of oil and natural gas properties or other assets in the future without any obligation to offer us the opportunity to purchase or participate in the development of those assets. In addition, the principal business of the EnerVest partnerships is to acquire and develop oil and natural gas properties. The agreements for certain of our EnerVest partnerships, however, provide that if EnerVest becomes aware, other than in its capacity as an owner of our general partner, of acquisition opportunities that are suitable for purchase by the EnerVest partnerships during their investment periods, EnerVest must first offer those opportunities to those EnerVest partnerships, in which case we would be offered the opportunities only if the EnerVest partnerships chose not to pursue the acquisition. EnerVest’s obligation to offer acquisition opportunities to its existing EnerVest partnership will not apply to acquisition opportunities which we generate internally, and EnerVest has agreed with us that for so long as it controls our general partner it will not enter into any agreements which would limit our ability to pursue acquisition opportunities that we generate internally.

Oil and Natural Gas Producing Activities

At December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin.

Barnett Shale

Our properties are primarily located in Denton, Montague, Parker, Tarrant and Wise counties in Northern Texas. Our estimated net proved reserves as of December 31, 2016 were 367.8 Bcfe, 65% of which is natural gas. During 2016, we drilled 9 gross wells in the Barnett Shale, which was successfully completed. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average 26% working interest in 1,560 gross productive wells.

San Juan Basin

Our properties are primarily located in Rio Arriba County, New Mexico and La Plata County in Colorado. Our estimated net proved reserves as of December 31, 2016 were 144.0 Bcfe, 66% of which is natural gas. During 2016, we did not drill any wells in the San Juan Basin. EnerVest operates wells representing 97% of our estimated net proved reserves in this area, and we own an average 77% working interest in 519 gross productive wells.

Appalachian Basin (including the Utica Shale)

Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties are producing primarily from the Knox and Clinton formations and other Devonian age sands in 40 counties in Eastern Ohio and 8 counties in Western Pennsylvania. Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 22 counties in North Central West Virginia. Our estimated net proved reserves as of December 31, 2016 were 136.4 Bcfe, 67% of which is natural gas. During 2016, we did not drill any wells in the Appalachian Basin. EnerVest operates wells representing 88% of our estimated net proved reserves in this area, and we own an average 71% working interest in 11,238 gross productive wells.

Michigan

Our properties are located in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves as of December 31, 2016 were 77.8 Bcfe, 96% of which is natural gas. During 2016, we did not drill any wells in Michigan. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 60% working interest in 1,586 gross productive wells.

Central Texas

Our properties produce primarily from the Austin Chalk formation and are located in 16 counties in Central Texas. Our portion of the estimated net proved reserves as of December 31, 2016 was 49.1 Bcfe, 42% of which is natural gas. During 2016, we did not drill any wells in Central Texas. EnerVest operates wells representing 97% of our estimated net proved reserves in this area, and we own an average 22% working interest in 1,462 gross productive wells.

Monroe Field

Our properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2016 were 27.9 Bcfe, 100% of which is natural gas. During 2016, we did not drill any wells in the Monroe Field. EnerVest operates wells representing 100% of our estimated net proved reserves in this area, and we own an average 100% working interest in 3,244 gross productive wells.

Mid–Continent Area

Our properties are primarily located in 43 counties in Oklahoma, 22 counties in Texas, four parishes in North Louisiana, two counties in Kansas and six counties in Arkansas. Our estimated net proved reserves as of December 31, 2016 were 27.8 Bcfe, 68% of which is natural gas. During 2016, we did not drill any wells in the Mid-Continent area. EnerVest operates wells representing 16% of our estimated net proved reserves in this area, and we own an average 24% working interest in 1,748 gross productive wells.

Permian Basin

Our properties are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties in New Mexico and Texas. Our estimated net proved reserves as of December 31, 2016 were 20.4 Bcfe, 37% of which is natural gas. During 2016, we did not drill any wells in the Permian Basin. EnerVest operates wells representing 99% of our estimated net proved reserves in this area, and we own an average 96% working interest in 136 gross productive wells.

Our Oil, Natural Gas and Natural Gas Liquids Data

Our Reserves

The following table presents our estimated net proved reserves at December 31, 2016:

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. Proved undeveloped reserves are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See “Glossary of Oil and Natural Gas Terms.” All proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.

Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which are believed to provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods are believed to provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The data in the above table represents estimates only. Oil, natural gas and natural gas liquids reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered. Please read “Item 1A. Risk Factors.”

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. 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 SEC, without giving effect to non–property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Because we are a limited partnership which passes through our taxable income to our unitholders, we have made no provisions for federal income taxes in the calculation of standardized measure; however, we have made a provision for future obligations under the Texas gross margin tax. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

Our Proved Undeveloped Reserves

We annually review all PUDs to ensure an appropriate plan for development exists. As of December 31, 2016, none of our PUDs have remained part of our PUD inventory for more than five years following the date they were initially classified as PUDs, except for 3.5% of our PUDs that require sidetracks of existing producing wells, in which case the development will occur when existing production ceases. We plan to convert our PUDs as of December 31, 2016 to proved developed reserves within five years of the date they were included as part of our PUD inventory of drilling locations, except for the sidetracks mentioned above, by drilling 144 gross wells at a total estimated capital cost of $61.9 million.

At December 31, 2016, we had 87.1 Bcfe of PUDs compared with 187.7 Bcfe of PUDs at December 31, 2015. The following table describes the changes in our PUDs during 2016:

The following describes the material changes to our PUDs during 2016:

Revisions of previous estimates. The annual review of our PUDs for 2016 resulted in a negative revision of 94.8 Bcfe. This change from prior estimates results from the decrease in prices for oil, natural gas and natural gas liquids used in our December 31, 2016 reserve estimates from prices used in our December 31, 2015 reserve estimates.

Sales of minerals in place. In December 2016, we sold oil and natural gas properties in the Barnett Shale and Austin Chalk areas. Of the 18.2 Bcfe of PUDs sold in 2016, 17.2 Bcfe were located in the Barnett Shale and the remaining 1.0 Bcfe were located in the Austin Chalk.

Extensions and discoveries. As we drill wells on our leases, reserves attributable to wells adjacent to the newly drilled wells may be added as extensions and discoveries to the PUD category. Extensions and discoveries were primarily due to increases in PUDs associated with our successful drilling activity in 2016 in the Barnett Shale and Austin Chalk. PUD additions in the Barnett Shale and Austin Chalk totaled 13.0 Bcfe and 0.7 Bcfe, respectively. We plan to drill these new PUDs within five years of January 1, 2017.

Converted to proved developed reserves. In 2016, we developed approximately 1% of our PUD volume and 1% of our PUD locations booked as of December 31, 2015 through the drilling of 2 gross (0.6 net) development wells. Of these reserves and wells, 1.3 Bcfe and 1 gross well are located in the Barnett Shale and the additional well and reserves are located in the Mid-Continent area. Costs incurred relating to the development of PUDs were approximately $0.4 million during 2016.

Internal Controls Applicable to our Reserve Estimates

Our policies and procedures regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations. Compliance with these rules and regulations is the responsibility of Terry Wagstaff, our Vice President of Acquisitions and Engineering, who is also our principal engineer. Mr. Wagstaff has over 35 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations and issues during most of this time, and is a qualified reserves estimator (“QRE”), as defined by the standards of the Society of Petroleum Engineers. Further professional qualifications include a Bachelor of Science in Petroleum Engineering, extensive internal and external reserve training, asset evaluation and management, and he is a registered professional engineer in the state of Texas. In addition, our principal engineer is an active participant in industry reserve seminars, professional industry groups, and is a member of the Society of Petroleum Engineers.

Our controls over reserve estimates included retaining Cawley Gillespie and Wright as our independent petroleum engineers. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Cawley Gillespie and Wright, and they prepared their own estimates of 89% and 11%, respectively, of our reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10–K is derived from the reports of Cawley Gillespie and Wright, which are included as exhibits to this annual report on Form 10–K.

The principal engineer at Cawley Gillespie responsible for preparing our reserve estimates is W. Todd Brooker, a President and Principal with Cawley Gillespie. Mr. Brooker is a licensed professional engineer in the state of Texas (license #83462) with over 25 years of experience in petroleum engineering. The principal engineer at Wright responsible for preparing our reserve estimates is D. Randall Wright, the President of Wright. Mr. Wright is a licensed professional engineer in the state of Texas (license #43291) with over 43 years of experience in petroleum engineering.

We and EnerVest maintain an internal staff of petroleum engineers, geoscience professionals and petroleum landmen who work closely with Cawley Gillespie and Wright to ensure the integrity, accuracy and timeliness of data furnished to Cawley Gillespie and Wright in their reserves estimation process. Our Vice President of Acquisitions and Engineering reviews and approves the reserve information compiled by our internal staff. Our technical team meets regularly with representatives of Cawley Gillespie and Wright to review properties and discuss the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates. Our technical team and Vice President of Acquisitions and Engineering also meet regularly to review the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.

The audit committee of our board of directors meets with management, including the Vice President of Acquisitions and Engineering, to discuss matters and policies related to our reserves.

Our Productive Wells

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2016. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest we hold in a given well. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells. Operated wells are the wells operated by EnerVest in which we own an interest.

Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.

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Our Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage as of December 31, 2016:

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Substantially all of our acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The acreage in which we hold interests that are not held by production are not significant to our overall undeveloped acreage.

Title to Properties

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

Production by Field

The following table sets forth our production for 2016, 2015 and 2014 from the Barnett Shale, the Appalachian Basin and the San Juan Basin, which are the only fields during those years for which our estimated net proved reserves at December 31, 2016 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2016:

Our Drilling Activity

We intend to concentrate our drilling activity on low risk development drilling opportunities. The number and types of wells we drill will vary depending on the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well, the estimated recoverable reserves attributable to each well and the accessibility to the well site.

The following table summarizes our approximate gross and net interest in development wells completed by us during 2016, 2015 and 2014, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

As of December 31, 2016, we were participating in the drilling of 1 gross (0.3 net) development well.

We did not drill any exploratory wells in 2016. We drilled three gross (1.7 net) exploratory wells in 2015, all of which were successfully completed as producers. We drilled six gross (2.7 net) exploratory wells in 2014, four of which were successfully completed as producers.

Well Operations

We have entered into operating agreements with EnerVest. Under these operating agreements, EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest, if our interest entitles us to control the appointment of the operator of the well, gathering system or production facilities. As contract operator, EnerVest designs and manages the drilling and completion of our wells and manages the day to day operating and maintenance activities for our wells.

Under these operating agreements, EnerVest has established a joint account for each well in which we have an interest. We are required to pay our working interest share of amounts charged to the joint account. The joint account is charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done in accordance with the Council of Petroleum Accountants Societies (“COPAS”) model form of accounting procedure.

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and wells, as well as gathering and other equipment used on our properties. In addition, direct expenses include the allocable share of the cost of services performed on our properties and wells by EnerVest employees. The allocation of the cost of EnerVest employees who perform services on our properties is based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account also include an amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.

Principal Customers, Marketing Arrangements and Delivery Commitments

The market for our oil, natural gas and natural gas liquids production depends on factors beyond our control, including the extent of domestic production and imports of oil, natural gas and natural gas liquids, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil, natural gas and natural gas liquids, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

Our oil, natural gas and natural gas liquids production is sold to a variety of purchasers. The terms of sale under the majority of existing contracts are short–term, usually one year or less in duration. The prices received for oil, natural gas and natural gas liquids sales are generally tied to monthly or daily indices as quoted in industry publications.

In 2016, Energy Transfer Partners, L.P., EnLink Midstream Partners, L.P. and Ergon Oil Purchasing, Inc. accounted for 18.5%, 13.4% and 10.4%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2015, Energy Transfer Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 17.1% and 10.8%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. In 2014, no customer accounted for greater than 10% of our consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.

Information regarding our delivery commitments is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” contained herein.

Competition

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and there can be no assurances that we will be able to compete satisfactorily when attempting to make further acquisitions.

Seasonal Nature of Business

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations primarily in certain areas of the Appalachian Basin, the San Juan Basin and Michigan. As a result, we generally perform the majority of our drilling in these areas during the summer and autumn months. In addition, the Monroe Field properties in Louisiana are subject to flooding. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can also lessen seasonal demand fluctuations.

Environmental, Health and Safety Matters and Regulation

Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the protection of the environment as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters. The US Environmental Protection Agency (the “EPA”) has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2017 and 2019 although it is unclear about the outlook for this initiative with the incoming administration.

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

Solid and Hazardous Waste Handling

The federal Resource Conservation and Recovery Act, or RCRA, and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount of the waste generated in our operations are regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. For example, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations, the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

Comprehensive Environmental Response, Compensation and Liability Act

The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Clean Water Act

The Federal Water Pollution Control Act, also known as the “Clean Water Act” and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the U.S. Army Corps of Engineers. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

Safe Drinking Water Act and Hydraulic Fracturing

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions but not at the federal level, as the federal Safe Drinking Water Act expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel). Due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality, there have been recent developments at the federal, state, regional and local levels that could result in regulation of hydraulic fracturing becoming more stringent and costly. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business.

Legislation was introduced in prior sessions of Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the Safe Drinking Water Act, and, further, to require disclosure of the chemicals used in the fracturing process, but did not pass. Also, some states and local or regional regulatory bodies have adopted, or are considering adopting, regulations that could restrict or ban hydraulic fracturing in certain circumstances or that require disclosure of chemical in the fracturing fluids. For example, New York has imposed a ban on hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed, and Wyoming and Texas have adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. States have also considered or adopted other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Further, the EPA has published guidance on hydraulic fracturing using diesel and has published an advanced notice of public rulemaking under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The Bureau of Land Management (“BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in June 2016 a Wyoming federal judge struck down this final rule, finding that the BLM lacked authority to promulgate the rule, and that decision is currently being appealed by the federal government. This litigation remains on appeal.

State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil and gas wastewater and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. Some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission rules allow it to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our assets.

Oil Pollution Act

The primary federal law for oil spill liability is the Oil Pollution Act, or OPA, which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain "responsible parties" related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable "responsible party" includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

Air Emissions  

Our operations are subject to the federal Clean Air Act, or CAA, and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring us to forego construction, modification or operation of certain air emission sources.

On April 17, 2012, the EPA issued final rules to subject oil and natural gas production, storage, processing and transmission operations to regulation under the New Source Performance Standards, or NSPS, and the National Emission Standards for Hazardous Air Pollutants, or NESHAPS, programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators have been required to capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.

The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources, The status of future regulation remains unclear but if adopted could require changes to our operations, including the installation of new emission control equipment. Simultaneously with the methane rules, EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations. In late 2016, BLM adopted rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged in court and remain in litigation. Additionally, the US House of Representatives has passed a resolution under the Congressional Review Act disapproving the rules; Senate action remains pending. If allowed to stand, these additional regulations on our air emissions is likely to result in increased compliance costs and additional operating restrictions on our business.

National Environmental Policy Act

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act, or NEPA, which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Depending on the mitigation strategies recommended in the Environmental Assessment or Environmental Impact Statement, we could incur added costs, which may be significant. Reviews and decisions under NEPA are also subject to protest or appeal, any or all of which may delay or halt projects. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

Climate Change Legislation

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. Some states, regions and localities have adopted or have considered programs to address GHG emissions. In addition, both houses of Congress previously considered legislation to reduce emissions of greenhouse gases and many states have adopted or considered measures to establish GHG emissions reduction levels, often involving the planned development of GHG emission inventories and/or GHG cap and trade programs. Most of these cap and trade programs would work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. Federal efforts at a cap and trade program appear to not be moving forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs. Depending on the regulatory reach of new CAA legislation implementing regulations or new EPA and/or state, regional or local rules restricting the emission of GHGs, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, the EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Compliance with these requirements has and is anticipated to require us to make investments in monitoring and recordkeeping equipment. We do not believe, however, that our compliance with applicable monitoring, recordkeeping and reporting requirements under GHG reporting program as recently amended will have a material adverse effect on our results of operations or financial position. We have submitted annual reports for emissions starting with our 2012 GHG emissions.

The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources. Further EPA has announced its intention to regulate methane emissions from existing oil and gas sources but the status of future regulation on existing sources remains unclear; if adopted, it could require changes to our operations, including the installation of new emission control equipment. Simultaneously with the methane rules for new and modified sources, EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations.

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could adversely affect the marketability of the oil, natural gas and natural gas liquids we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

Endangered Species Act

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under the act. The U.S. Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected leases.

OSHA and Other Laws and Regulation 

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act, or OSHA, and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable state statute requirements.

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2016, 2015 and 2014. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2017 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact our business activities, financial condition, results of operations or ability to pay distributions to our unitholders.

Other Regulation of the Oil and Natural Gas Industry

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

Drilling and Production

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. Our drilling and production operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties and impose bonding requirements in order to drill and operate wells. Some states have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the Bureau of Land Management (the “BLM”), Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits ownership of any direct or indirect interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign entity except through equity ownership in a corporation formed under the laws of the United States or of any U.S. State or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or entities of the United States. If these restrictions are violated, the oil and natural gas lease can be canceled in a proceeding instituted by the United States Attorney General. We qualify as an entity formed under the laws of the United States or of any U.S. State or territory. Although the regulations promulgated and administered by the BLM pursuant to the Mineral Act provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that our unitholders may be citizens of foreign countries and do not own their units in a U.S corporation or even if such interest held through a U.S. corporation, their country of citizenship may be determined to be a non–reciprocal country under the Mineral Act. In such event, any federal onshore oil and natural gas leases held by us could be subject to cancellation based on such determination.

Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

Since 1985, FERC has implemented regulations intended to increase competition within the natural gas industry by making natural gas transportation more accessible to natural gas buyers and sellers on an open-access, nondiscriminatory basis.

Sales of our oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act. The FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In August 2011, the PHMSA issued an Advance Notice of Proposed Rulemaking regarding pipeline safety, including questions regarding the modification of regulations applicable to gathering lines in rural areas.

Transportation of our oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

In addition, the U.S. federal government has recently ended its decades–old prohibition of exports of oil produced in the lower–48 states of the U.S. It is too recent an event to determine the impact this regulatory change may have on our operations or our sales of oil.

Although natural gas sales prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of oil and natural gas liquids are not currently regulated and are made at market prices.

Hydraulic Fracturing

Most of our oil and natural gas properties are subject to hydraulic fracturing to economically develop the properties. The hydraulic fracturing process is integral to our drilling and completion costs in these areas and typically represent up to 60% of the total drilling/completion costs per well.

We diligently review best practices and industry standards, and comply with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non–commercially produced fluids in certified disposal wells at depths below the potable water sources.

In compliance with laws enacted in various states, we will disclose hydraulic fracturing data to the appropriate chemical registry. These laws generally require disclosure for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment.

There have not been any material incidents, citations or suits related to our hydraulic fracturing activities involving violations of environmental laws and regulations.

Other Regulation

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our unitholders.

Insurance

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for control of well, general liability (includes sudden and accidental pollution), physical damage to our oil and gas natural properties, auto liability, worker's compensation and employer's liability, among other things.

Currently, we have general liability insurance coverage up to $1.0 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain $100.0 million in excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, we believe our general liability and excess liability insurance policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

We re–evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to self–insure or maintain only catastrophic coverage for certain risks in the future.

Employees

EV Management, the general partner of our general partner, has seven full time employees who spend a significant amount of their time on our operations. At December 31, 2016, EnerVest, the sole member of EV Management, had approximately 1,100 full–time employees, including over 103 geologists, engineers and land professionals. To carry out our operations, EnerVest employs the people who will provide direct support to our operations. None of these employees are covered by collective bargaining agreements. We consider EV Management’s relationship with its employees to be good, and EnerVest considers its relationship with its employees to be good.

Offices

We do not have any material owned or leased property (other than our interests in oil and gas properties). Under our omnibus agreement, EnerVest provides us office space for our executive officers and other employees at EnerVest’s offices in Houston, Texas.

Available Information

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), are made available free of charge on our website at www.evenergypartners.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. These documents are also available on the SEC’s website at www.sec.gov or you may read and copy any materials that we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE, Washington DC 20549. Our website also includes our Code of Business Conduct and the charters of our audit committee and compensation committee. No information from either the SEC’s website or our website is incorporated herein by reference.

ITEM 1A. RISK FACTORS

Limited partner interests are inherently different from capital stock of a corporation, although many of the business risks to which we are subject are similar to those that would be faced by a corporation engaged in similar businesses. If any of the following risks were actually to occur, our business, financial condition or results of operations or cash flows could be materially adversely affected.  

Risks Related to Our Business

We may not have sufficient cash from operations following the establishment of cash reserves and payment of fees and expenses, including cost reimbursements to our general partner, to enable us to resume cash distributions to holders of our common units.

We have suspended cash distributions to the holders of our common units in order to conserve cash and improve our liquidity.

We may not have sufficient available cash from operating surplus each quarter to enable us to resume making cash distributions under our cash distribution policy. The amount of cash we can distribute on our units principally depends upon the amount of cash we generate from our operations, which will fluctuate from quarter to quarter based on, among other things:

In addition, the actual amount of cash we will have available for distribution will depend on other factors, some of which are beyond our control, including:

As a result of these factors, we may not have sufficient available cash to resume our quarterly cash distributions to our common unitholders. Even if we were able to resume a quarterly cash distribution, the amount of available cash that we could distribute may fluctuate significantly from quarter to quarter. In order to reinstate distributions, we must be in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors - Covenants in our credit agreement may restrict our ability to resume and sustain distributions.

Covenants in our credit agreement may restrict our ability to resume and sustain distributions.

The terms of our credit agreement may restrict our ability to pay distributions if we do not satisfy the financial and other covenants in the facility. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent ninth amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions.

Oil, natural gas and natural gas liquids prices are highly volatile and depressed prices can significantly and adversely affect our cash flows from operations and our ability to service our debt obligations and resume distributions on our common units.

Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and natural gas liquids. Prices for these commodities have been depressed when compared with historical prices. The prices we receive for our production are volatile and a drop in prices can significantly affect our financial results and impede our growth, including our ability to maintain or increase our borrowing capacity, to repay current or future indebtedness and to obtain additional capital on attractive terms, all of which can affect our ability to pay distributions. Changes in prices have a significant impact on the value of our reserves and on our cash flows. Prices may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

Low prices will decrease our revenues, but may also reduce the amount of oil, natural gas or natural gas liquids that we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. We may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period taken and our ability to borrow funds under our credit facility, which may adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.

Low commodity prices or further declines would have a material adverse effect on our business.

Our financial position, results of operations, access to capital and the quantities of oil and natural gas that may be economically produced would be negatively impacted if oil and natural gas prices decrease further or remain depressed for an extended period of time. The ways in which such price decreases could have a material negative effect include:

Future oil and natural gas price declines may result in a write-down of our asset carrying values.

Accounting rules require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write–down. During 2016, we recorded impairment charges of approximately $131.3 million. The impairment charges during 2016 included $89.5 million related to oil and natural gas properties in the Barnett Shale that were written down to their fair value as determined based on the sale of these properties during December 2016. We also may incur impairment charges in the future, which could have a material adverse effect on our results of operations in the period incurred. Since December 31, 2016, commodity prices have continued to fluctuate. If commodity prices significantly decrease before March 31, 2017, or in future quarters, we could have additional impairments of our oil and natural gas properties.

We may be limited in our ability to maintain or book additional proved undeveloped reserves under the SEC’s rules.

Our estimates of our proved reserves as of December 31, 2016 have been prepared in a manner consistent with our interpretation of the SEC rules relating to reserve estimation and disclosure requirements for oil and natural gas companies, as well as the interpretation of our independent petroleum consultants performing an audit of our reserve estimates. Included within these SEC reserve rules is a general requirement that, subject to limited exceptions, PUD’s may only be classified as such if a development plan has been adopted indicating that they are scheduled to be drilled within five years of the date of booking. This rule may limit our potential to book additional PUD’s as we pursue our drilling program. Further, if we postpone drilling of PUD’s beyond this five-year development horizon, whether in response to a continued depressed commodity price environment or otherwise, we may have to write off reserves previously recognized as PUD’s. Our long–term plans may change based on commodity prices, costs or our liquidity in a manner that would require us to reduce our proved reserve estimate in the future due to the five year development rule or otherwise.

Our identified potential drilling locations, which are part of our anticipated future drilling plans, are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling and result in changes to the amount of our proved undeveloped reserves.

As of December 31, 2016, we had over 3,014 gross identified potential drilling locations, of which approximately 1,400 were located in the Barnett Shale and approximately 1,000 were located in the Appalachian Basin. This inventory was developed using data gathered from our appraisal efforts and development drilling, along with offset operators drilling activities. As of December 31, 2016, we included reserves attributable to 144 of our gross identified potential drilling locations in our proved undeveloped reserves category, of which approximately 90 were located in the Barnett Shale. These drilling locations, including those without proved undeveloped reserves, represent a part of our growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. Further, our identified potential drilling locations are in various stages of evaluation, ranging from locations that are ready to drill to locations that will require substantial additional interpretation. We cannot predict in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. Because of these uncertainties, we do not know if the potential drilling locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Future development of proved undeveloped reserves attributable to our interests in properties EnerVest does not operate will be subject to decisions of the operator which will be beyond our control.

Approximately 10% of our total estimated proved reserves as of December 31, 2016 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations. The reserve data included in the reserve reports of our independent petroleum engineers assume that we will have the financing to make the substantial capital expenditures required to develop such reserves. We cannot be certain that the estimated costs of the development of these reserves are accurate, that our projections of the ability to finance these future costs will be realized, that development will occur as scheduled or that the results of such development will be as estimated. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in oil, natural gas or natural gas liquids prices will reduce the future net revenues of our estimated proved undeveloped reserves and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves. In addition, the decision of the operators to develop the proved undeveloped reserves attributable to our properties that EnerVest does not operate will be subject to the business plans and constraints of the operators of these properties, and be beyond our control.

We currently own interests in oil and natural gas properties in which partnerships managed by EnerVest also own an interest and we may acquire properties in which the EnerVest managed partnerships own an interest in the future. If the EnerVest partnerships elect to sell their interest in these properties, we would own a minority interest in the properties, and EnerVest may lose the ability to operate the properties.

We own interests in oil and natural gas properties in which partnerships managed by EnerVest also own interests, and we expect to make acquisitions of properties jointly with EverVest partnerships in the future. These properties are primarily in the Barnett Shale and Central Texas, and these properties represent approximately 49% of our estimated net proved reserves as of December 31, 2016. The EnerVest partnerships generally have an investment strategy to typically divest properties in three to five years, while our strategy is to hold properties for the longer term. We own less than a majority working interest in the properties in which the EnerVest partnerships also own an interest. If the EnerVest partnerships were to sell their interest in these properties to an entity not affiliated with EnerVest, our working interest would not be large enough that we could control the selection of the operator and EnerVest may lose the ability to operate the properties on our behalf. Loss of operations would mean that EnerVest would no longer control decisions regarding the development and production of those properties, and any replacement operator could make decisions regarding development or production activities that make it difficult to implement our strategy.

We depend on EnerVest to provide us services necessary to operate our business. If EnerVest were unable or unwilling to provide these services, it would result in disruption in our business which could have an adverse effect on our ability to resume cash distributions to our unitholders and service our debt obligations.

Under an omnibus agreement, EnerVest provides services to us such as accounting, human resources, office space and other administrative services, and under an operating agreement, EnerVest operates our properties for us. If EnerVest were to become unable or unwilling to provide such services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our ability to resume cash distributions to our unitholders and our business, and the services, when developed or retained, may not be of the same quality as provided to us by EnerVest.

Our hedging transactions may limit our gains and expose us to counterparty credit risk.

We enter into derivative contracts from time to time to manage our exposure to fluctuations in oil, natural gas and natural gas liquids prices. These derivative contracts limit our potential gains if prices rise above the fixed prices established by the derivative contracts. These derivative contracts may also expose us to other risks of financial losses, for example, if our production is less than we anticipated at the time we entered into the derivatives contract. Similarly, during periods of falling commodity prices, our derivative contracts expose us to risk of financial loss if the counterparty to the derivative contract fails to perform its obligations under the derivative contract (e.g., our counterparty fails to perform its obligation to make payments to us under the derivative contract when the market (floating) price under such derivative contract falls below the specified fixed price). To mitigate counterparty credit risk, we conduct our hedging activities with financial institutions who are lenders under our credit facility. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

Our hedging activities could result in financial losses or could reduce our net income, which may adversely affect our ability to pay cash distributions to our unitholders and service our debt obligations.

To achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids, we have and may continue to enter into hedging arrangements for a significant portion of our production. If we experience a sustained material interruption in our production, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity. Lastly, an attendant risk exists in hedging activities that the counterparty in any derivative transaction cannot or will not perform under the instrument and that we will not realize the benefit of the hedge.

Our ability to use hedging transactions to protect us from future price declines will be dependent upon oil and natural gas prices at the time we enter into future hedging transactions and our future levels of hedging, and as a result our future net cash flows may be more sensitive to commodity price changes.

Our policy has been to hedge a significant portion of our near–term estimated production. However, our price hedging strategy and future hedging transactions will be determined at the discretion of our general partner, which is not under an obligation to hedge a specific portion of our production. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases. Relative to previous years, we have less volumes hedged at lower prices. This makes our near-term oil, natural gas and natural gas liquids revenues more sensitive to changes in commodity prices.

Our limited ability to hedge our natural gas liquids production could adversely impact our net cash provided by operating activities and results of operations.

A liquid, readily available and commercially viable market for hedging natural gas liquids has not developed in the same way that exists for oil and natural gas. The current direct natural gas liquids hedging market is constrained in terms of price, volume, duration and number of counterparties, which limits our ability to hedge our natural gas liquids production effectively or at all. As a result, our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for natural gas liquids.

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.  

Title VII of the Dodd-Frank Act establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including crude oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or the Federal Energy Regulatory Commission (“FERC”), we could be subject to substantial penalties and fines.

Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation.  While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements.  We also must comply with the anti-market manipulation rules enforced by FERC under the NGA.  Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps.  Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time.  Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.

The distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

Some of our customers may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

We may be unable to integrate successfully the operations of our recent or future acquisitions with our operations and we may not realize all the anticipated benefits of the recent acquisitions or any future acquisition.

Integration of our recent acquisitions with our business and operations has been a complex, time consuming and costly process. Failure to successfully assimilate our past or future acquisitions could adversely affect our financial condition and results of operations.

Our acquisitions involve numerous risks, including:

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers against such liabilities, which could adversely affect our cash available for distribution and for servicing our debt obligations.

One of our growth strategies is to capitalize on opportunistic acquisitions of oil, natural gas and natural gas liquids reserves. Any future acquisition will require an assessment of recoverable reserves, title, future oil, natural gas and natural gas liquids prices, operating costs, potential environmental hazards, potential tax and ERISA liabilities, and other liabilities and similar factors. Ordinarily, our review efforts are focused on the higher valued properties and are inherently incomplete because it generally is not feasible to review in depth every individual property involved in each acquisition. Even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit a buyer to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and potential problems, such as ground water contamination and other environmental conditions and deficiencies in the mechanical integrity of equipment are not necessarily observable even when an inspection is undertaken. Any unidentified problems could result in material liabilities and costs that negatively impact our financial conditions and results of operations and our ability to resume and sustain cash distributions to our unitholders and service our debt obligations.

Additional potential risks related to acquisitions include, among other things:

If we consummate any future acquisitions, our capitalization and results of operations may change significantly.

Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flows from operations and our ability to resume or sustain distributions to our unitholders or service our debt obligations.

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when we drill additional wells, make acquisitions or under other circumstances. Our future cash flows and income and our ability to resume, maintain and increase distributions to unitholders are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil, natural gas and natural gas liquids prices and the number and attractiveness of properties for sale.

Our estimated reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

Numerous uncertainties are inherent in estimating quantities of our reserves. Our estimates of our net proved reserve quantities are based upon reports from Cawley Gillespie and Wright, independent petroleum engineering firms used by us. The process of estimating oil, natural gas and natural gas liquids reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil, natural gas and natural gas liquids prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and natural gas liquids attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices for the 12 months preceding the date of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations, financial condition and our ability to make cash distributions to our unitholders.

Our acquisition and development operations will require substantial capital expenditures, which will reduce our cash available for distribution. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the development, production and acquisition of reserves. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical well, sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

Our capital expenditures will be deducted from our revenues in determining our cash available for distribution. We intend to finance our future capital expenditures with cash flows from operations, borrowings under our credit facility and the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

 If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, and could adversely affect our business, results of operation, financial conditions and ability to make distributions to our unitholders. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

We rely on development drilling to assist in maintaining our levels of production. If our development drilling is unsuccessful, our cash available for distributions and for servicing our debt obligations and financial condition will be adversely affected.

Part of our business strategy has focused on maintaining production levels by drilling development wells. Although we were successful in development drilling in the past, we cannot assure you that we will continue to maintain production levels through development drilling, particularly in the current commodity price environment. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for distribution to our unitholders and for servicing our debt obligations.

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

Our business strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.

Our operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:

Difficulties that we face while completing our wells include the following:

In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.

We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the U.S. oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program.

We may be unable to compete effectively with larger companies, which may adversely affect our ability to generate sufficient revenue and our ability to pay distributions to our unitholders and service our debt obligations.

The oil and natural gas industry is intensely competitive, and we compete with other companies that have greater resources than us. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Many of our larger competitors not only drill for and produce oil, natural gas and natural gas liquids, but also carry on refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for oil and natural gas properties and evaluate, bid for and purchase a greater number of properties than our financial or human resources permit. In addition, these companies may have a greater ability to continue drilling activities during periods of low prices, to contract for drilling equipment, to secure trained personnel, and to absorb the burden of present and future federal, state, local and other laws and regulations. The oil and natural gas industry has periodically experienced shortages of drilling rigs, equipment, pipe and personnel, which has delayed development drilling and other exploitation activities and has caused significant price increases. Competition has been strong in hiring experienced personnel, particularly in the accounting and financial reporting, tax and land departments. In addition, competition is strong for attractive oil and natural gas producing properties, oil and natural gas companies, and undeveloped leases and drilling rights. We may be often outbid by competitors in our attempts to acquire properties or companies. Our inability to compete effectively with larger companies could have a material adverse impact on our business activities, financial condition and results of operations.  

Our business is subject to operational risks that will not be fully insured, which, if they were to occur, could adversely affect our financial condition or results of operations and, as a result, our ability to pay distributions to our unitholders and service our debt obligations.

Our business activities are subject to operational risks, including:

In addition, a portion of our natural gas production is processed to extract natural gas liquids at processing plants that are owned by others. If these plants were to cease operations for any reason, we would need to arrange for alternative transportation and processing facilities. These alternative facilities may not be available, which could cause us to shut–in our natural gas production, or the alternative facilities could be more expensive than the facilities we currently use.

Any of these events could adversely affect our ability to conduct operations or cause substantial losses, including personal injury or loss of life, damage to or destruction of property, natural resources and equipment, pollution or other environmental contamination, loss of wells, regulatory penalties, suspension of operations, and attorneys’ fees and other expenses incurred in the prosecution or defense of litigation.

As is customary in the industry, we maintain insurance against some but not all of these risks. Additionally, we may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the perceived risks presented. Losses could therefore occur for uninsurable or uninsured risks or in amounts in excess of existing insurance coverage. The occurrence of an event that is not fully covered by insurance could have a material adverse impact on our business activities, financial condition, results of operations and ability to pay distributions to our unitholders and service our debt obligations.

Our business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third-party transporters and we rely on third parties to gather and deliver our oil, natural gas and NGLs to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and natural gas liquids we produce and could reduce our revenues and cash available for distribution.

The marketability of our oil, natural gas and natural gas liquids production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues and cash available for distribution.

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition, results of operations and ability to resume distributions to our unitholders.

Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

 We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

Our operations are subject to complex and stringent laws and regulations, which are continuously being reviewed for amendment and/or expansion. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and natural gas liquids we may produce and sell.

We are subject to, and may incur liabilities under, federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration and production of oil, natural gas and natural gas liquids.

For example, several states have enacted Surface Damage Acts (“SDAs”) that are designed to compensate surface owners/users for damages caused by mineral owners. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. In addition, many states, including Texas, impose a production, ad valorem or severance tax with respect to the production and sale of oil and gas within their jurisdiction.

Other activities subject to regulation are:

While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to pay distributions to our unitholders and service our debt obligations could be adversely affected.

Climate change legislation or regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids we produce.

The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual basis.

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply.

Both houses of Congress previously considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce. Federal efforts at a cap and trade program appear to not be moving forward in Congress. Some members of Congress have publicly indicated an intention to introduce legislation to curb EPA’s regulatory authority over GHGs.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. The EPA has adopted rules to regulate methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources, although it remains unclear the status of future rulemaking under the new administration, This rule is also the subject of pending appeals. In late 2016, BLM adopted rules governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. These rules have been challenged in court and remain in litigation. Additionally, the US House of Representatives has passed a resolution under the Congressional Review Act disapproving the rules; Senate action remains pending.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

In an interpretative guidance on climate change disclosures, the SEC indicates that climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate related damages to our facilities in our costs of operation potentially arising from such climatic effects, less efficient or non–routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing could result in increased costs and additional operating restrictions or delays.

Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from dense rock formations. The hydraulic fracturing process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing techniques in most of our drilling and completion programs. Hydraulic fracturing is typically regulated by state oil and natural gas commissions but the EPA has asserted federal regulatory authority pursuant to the Safe Drinking Water Act over certain hydraulic fracturing activities involving the use of diesel. In addition, in past sessions, legislation was introduced before Congress to provide for federal regulation of hydraulic fracturing under the Safe Drinking Water Act and to require disclosure of the chemicals used in the fracturing process. At the state level, some states, including Pennsylvania, Louisiana and Texas, where we operate, have adopted, and other states are considering adopting, requirements that could impose more stringent permitting, public disclosure or well construction requirements on hydraulic fracturing activities including such things as restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing. In the event that new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.

In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. This interpretation by the EPA may constitute an expansion of federal jurisdiction over waters of the United States. The rule was stayed nationwide by the U.S. Sixth Circuit Court of Appeals in October 2015 as that appellate court and several other courts hear lawsuits opposing implementation of the rule. In January 2017, the United States Supreme Court accepted review of the rule to determine whether jurisdiction rests with the federal district or appellate courts. Litigation surrounding this rule is ongoing. Further, the EPA has published guidance on hydraulic fracturing using diesel and has published an advanced notice of public rulemaking under the Toxic Substances Control Act to develop regulations governing the disclosure and evaluation of hydraulic fracturing chemicals. Further, in June 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. This ongoing scrutiny of hydraulic fracturing, depending on the degree of pursuit and any meaningful results obtained, could result in further regulation of hydraulic fracturing under the federal Safe Drinking Water Act or other regulatory programs.

We are now subject to regulation under NSPS and NESHAPS programs, which could result in increased operating costs.

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to newly fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.

Changes in interest rates could adversely impact our unit price and our ability to issue additional equity and incur debt.

Interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly. As with other yield oriented securities, our unit price is impacted by the level of our cash distributions and implied distribution yield. The distribution yield is often used by investors to compare and rank related yield oriented securities for investment decision-making purposes. Therefore, changes in interest rates, either positive or negative, may affect the yield requirements of investors who invest in our units, and a rising interest rate environment could have an adverse impact on our unit price and our ability to issue additional equity to make acquisitions, incur debt or for other purposes.

We may encounter obstacles to marketing our oil, natural gas and natural gas liquids, which could adversely impact our revenues.

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by U.S. federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of our units and our ability to pay distributions on our units and service our debt obligations.

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our production and our revenues and cash available for distribution could decline which could adversely affect our ability to make cash distributions to our unitholders and service our debt obligations.

Our ability to make cash distributions depends on our ability to successfully drill and complete wells on our properties. Seasonal weather conditions and lease stipulations may adversely affect our ability to conduct drilling and production activities in some of the areas where we operate.

Drilling and producing operations in the Appalachian Basin, the San Juan Basin and Michigan are adversely affected by seasonal weather conditions, primarily in the spring. Many municipalities in Appalachia impose weight restrictions on the paved roads that lead to our jobsites due to the muddy conditions caused by spring thaws. In addition, our Monroe Field properties in Louisiana are subject to flooding. This limits our access to these jobsites and our ability to service wells in these areas on a year around basis.

The amount of cash we have available for distribution to holders of our common units depends primarily on our cash flows and not our profitability.

The amount of cash that we have available for distribution depends primarily upon our cash flows, including financial reserves and cash flows from working capital, or other borrowings, and not solely on profitability, which is affected by noncash items. As a result, we may be unable to resume the payment of distributions even when we record net income and we may be able to resume the payment of distributions during periods when we incur net losses.

Any significant reduction in our borrowing base under our credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations, and we may not have sufficient funds to repay borrowings under our credit facility if required as a result of a borrowing base redetermination.

Availability under our credit facility is currently subject to a borrowing base of $450.0 million. The borrowing base is subject to scheduled semiannual and other elective collateral borrowing base redeterminations based on the value of our oil and natural gas reserves as determined by the lenders under our credit facility, and other factors deemed relevant by our lenders. Additional declines in prices for oil, natural gas and natural gas liquids may cause our banks to further reduce the borrowing base under our credit facility. As of December 31, 2016, we had outstanding borrowings of $265.0 million which bore a weighted average effective interest rate of 3.75%. We intend to continue borrowing under our credit facility in the future. Any significant reduction in our borrowing base as a result of such borrowing base redeterminations or otherwise may negatively impact our liquidity and our ability to fund our operations and, as a result, may have a material adverse effect on our financial position, results of operation and cash flow. Further, if the outstanding borrowings under our credit facility were to exceed the borrowing base as a result of any such redetermination, we would be required to repay the excess. We may not have sufficient funds to make such repayments. If we do not have sufficient funds and we are otherwise unable to negotiate renewals of our borrowings or arrange new financing, we may have to sell significant assets. Any such sale could have a material adverse effect on our business and financial results.

We have significant indebtedness under our credit facility and our 8% senior notes due April 2019. Restrictions in our credit facility and our 8% senior notes due April 2019 may limit our ability to resume and sustain distributions to our unitholders and may limit our ability to capitalize on acquisitions and other business opportunities.

Our credit facility and 8% senior notes due April 2019 contain covenants limiting our ability to make distributions, incur indebtedness, grant liens, make acquisitions, investments or dispositions and engage in transactions with affiliates, as well as containing covenants requiring us to maintain certain financial ratios and tests. The requirement that we comply with these provisions may materially adversely affect our ability to make distributions to our unitholders, react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continued or future downturn in our business. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and expect to be in compliance through the end of 2017. Absent a rebound in commodity prices or an amendment to our credit facility, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018. See Item 1A. Risk Factors – Covenants in our credit agreement may restrict our ability to resume and sustain distributions.

We may incur substantial debt in the future to enable us to maintain or increase our production levels and to otherwise pursue our business plan. This debt may restrict our ability to resume or sustain distributions to our unitholders and service our debt obligations.

Our business requires a significant amount of capital expenditures to maintain and grow production levels. Commodity prices have historically been volatile, and we cannot predict the prices we will receive in the future. If prices were to decline for an extended period of time, if the costs of our acquisition and development operations were to increase substantially, or if other events were to occur which reduced our revenues or increased our costs, we may be required to borrow significant amounts in the future to enable us to finance the expenditures necessary to replace the reserves we produce. The cost of the borrowings and our obligations to repay the borrowings will reduce amounts otherwise available for distributions to our unitholders.

Oil and gas exploration and production activities are complex and involves risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course our business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters, in the ordinary course of our business. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

Loss of our information and computer systems could adversely affect our business.

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

Cyber–attacks targeting systems and infrastructure used by the oil and natural gas industry may adversely impact our operations.

Our business has become increasingly dependent on digital technologies to conduct certain exploration, development, production and financial activities. We depend on digital technology to estimate quantities of oil and natural gas reserves, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Unauthorized access to our seismic data, reserves information or other proprietary information could lead to data corruption, communication interruption, or other operational disruptions in our exploration or production operations. Also, computers control nearly all of the oil and natural gas distribution systems in the U.S. and abroad, which are necessary to transport our production to market. A cyber–attack directed at oil and natural gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions.

While we have not experienced cyber–attacks, there is no assurance that we will not suffer such attacks and resulting losses in the future. Further, as cyber–attacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyber-attacks.

Risks Inherent in an Investment in Us

The price of our units could be subject to wide fluctuations and unitholders could lose a significant part of their investment.

From the beginning of 2015 through the fourth quarter of 2016, the quoted market prices of our common units fluctuated from a high of $21.38 to a low of $1.51. The market prices of our common units are subject to fluctuations in response to a number of factors, most of which we cannot control, including, but not limited to:

In recent years, the securities market has experienced extreme price and volume fluctuations. This volatility has had a significant effect on the market price of securities issued by many companies for reasons unrelated to the operating performance of these companies. Future market fluctuations may result in a lower price of our common units.

We do not have the same flexibility as other types of organizations to accumulate cash and equity to protect against illiquidity in the future.

Unlike a corporation, our limited partnership agreement requires us to make distributions to our unitholders of all available cash reduced by any amounts of reserves for commitments and contingencies, including capital and operating costs and debt service requirements. The value of our units may decrease in direct correlation with decreases in the amount we distribute per unit. Accordingly, if we experience a liquidity problem in the future, we may have difficulty issuing more equity to recapitalize.

EnerVest controls our general partner, which has sole responsibility for conducting our business and managing our operations. EnerVest, EV Investors, L.P. (“EV Investors”) and EnCap Investments, L.P. (“EnCap”), which are limited partners of our general partner, will have conflicts of interest, which may permit them to favor their own interests to your detriment.

EnerVest owns and controls our general partner and EnCap owns a 23.75% limited partnership interest in our general partner. Conflicts of interest may arise between EnerVest, EnCap and their respective affiliates, including our general partner, on the one hand, and us, our unitholders and the holders of our debt obligations, on the other hand. In resolving these conflicts of interest, our general partner may favor its own interests and the interests of its owners over the interests of our unitholders and the holders of our debt obligations. These conflicts include, among others, the following situations:

Many of the directors and officers who have responsibility for our management have significant duties with, and will spend significant time serving, entities that compete with us in seeking out acquisitions and business opportunities and, accordingly, may have conflicts of interest in allocating time or pursuing business opportunities.

In order to maintain and increase our levels of production, we will need to acquire oil and natural gas properties. Several of the officers and directors of EV Management, the general partner of our general partner, who have responsibilities for managing our operations and activities hold similar positions with other entities that are in the business of identifying and acquiring oil and natural gas properties. For example, Mr. John B. Walker is Executive Chairman of EV Management and Chief Executive Officer of EnerVest, which is in the business of acquiring oil and natural gas properties and managing the EnerVest partnerships that are in that business. Mr. Kenneth Mariani, a director of EV Management, is also President of EnerVest. We cannot assure you that these conflicts will be resolved in our favor. Mr. Gary R. Petersen, a director of EV Management, is also a senior managing director of EnCap, which is in the business of investing in oil and natural gas companies with independent management which in turn is in the business of acquiring oil and natural gas properties. Mr. Petersen is also a director of several oil and natural gas producing entities that are in the business of acquiring oil and natural gas properties. The existing positions of these directors and officers may give rise to fiduciary obligations that are in conflict with fiduciary obligations owed to us. The EV Management officers and directors may become aware of business opportunities that may be appropriate for presentation to us as well as the other entities with which they are or may be affiliated. Due to these existing and potential future affiliations with these and other entities, they may have fiduciary obligations to present potential business opportunities to those entities prior to presenting them to us, which could cause additional conflicts of interest. They may also decide that the opportunities are more appropriate for other entities which they serve and elect not to present them to us.

Neither EnerVest nor EnCap is limited in its ability to compete with us for acquisition or drilling opportunities. This could cause conflicts of interest and limit our ability to acquire additional assets or businesses which in turn could adversely affect our ability to replace reserves, results of operations and cash available for distribution to our unitholders and for servicing our debt obligations.

Neither our partnership agreement nor the omnibus agreement between EnerVest and us prohibits EnerVest, EnCap and their affiliates from owning assets or engaging in businesses that compete directly or indirectly with us. For instance, EnerVest, EnCap and their respective affiliates may acquire, develop or dispose of additional oil or natural gas properties or other assets in the future, without any obligation to offer us the opportunity to purchase or develop any of those assets. Each of these entities is a large, established participant in the energy business, and each has significantly greater resources and experience than we have, which factors may make it more difficult for us to compete with these entities with respect to commercial activities as well as for acquisition candidates. As a result, competition from these entities could adversely impact our results of operations and accordingly cash available for distribution and for servicing our debt obligations.

Cost reimbursements due to our general partner and its affiliates for services provided may be substantial and will reduce our cash available for distribution to our unitholders and for servicing our debt obligations.

Pursuant to the omnibus agreement between EnerVest and us, EnerVest will receive reimbursement for the provision of various general and administrative services for our benefit. In addition, we entered into contract operating agreements with a subsidiary of EnerVest pursuant to which the subsidiary will be the contract operator of all of the wells for which we have the right to appoint an operator. Payments for these services will be substantial and will reduce the amount of cash available for distribution to unitholders. In addition, under Delaware partnership law, our general partner has unlimited liability for our obligations, such as our debts and environmental liabilities, except for our contractual obligations that are expressly made without recourse to our general partner. To the extent our general partner incurs obligations on our behalf, we are obligated to reimburse or indemnify it. If we are unable or unwilling to reimburse or indemnify our general partner, our general partner may take actions to cause us to make payments of these obligations and liabilities. Any such payments could reduce the amount of cash otherwise available for distribution to our unitholders.

Our partnership agreement limits our general partner’s fiduciary duties to holders of our common units.

Although our general partner has a fiduciary duty to manage us in a manner beneficial to us and our unitholders, the directors and officers of EV Management, the general partner of our general partner, have a fiduciary duty to manage our general partner in a manner beneficial to its owners. Our partnership agreement contains provisions that reduce the standards to which our general partner and its affiliates would otherwise be held by state fiduciary duty laws. For example, our partnership agreement permits our general partner and its affiliates to make a number of decisions either in their individual capacities, as opposed to in its capacity as our general partner, or otherwise free of fiduciary duties to us and our unitholders. This entitles our general partner and its affiliates to consider only the interests and factors that they desire, and they have no duty or obligation to give any consideration to any interest of, or factors affecting, us, our affiliates or any limited partner. Examples include:

Our partnership agreement restricts the remedies available to holders of our common units for actions taken by our general partner that might otherwise constitute breaches of fiduciary duty.

Our partnership agreement contains provisions restricting the remedies available to unitholders for actions taken by our general partner or its affiliates that might otherwise constitute breaches of fiduciary duty. For example, our partnership agreement:

Our general partner may elect to cause us to issue Class B units to it in connection with a resetting of the target distribution levels related to our general partner’s incentive distribution rights without the approval of the conflicts committee or holders of our common units. This may result in lower distributions to holders of our common units in certain situations.

Our general partner has the right to reset the cash target distribution levels at higher levels based on the distribution at the time of the exercise of the reset election. Following a reset election by our general partner, the minimum quarterly distribution amount will be reset to an amount equal to the average cash distribution amount per common unit for the two fiscal quarters immediately preceding the reset election (such amount is referred to as the “reset minimum quarterly distribution”) and the target distribution levels will be reset to correspondingly higher levels based on percentage increases above the reset minimum quarterly distribution amount.

In connection with resetting these target distribution levels, our general partner will be entitled to receive a number of Class B units. The Class B units will be entitled to the same cash distributions per unit as our common units and will be convertible into an equal number of common units. The number of Class B units to be issued will be equal to that number of common units whose aggregate quarterly cash distributions equaled the average of the distributions to our general partner on the incentive distribution rights in the prior two quarters. We anticipate that our general partner would exercise this reset right in order to facilitate acquisitions or internal growth projects that would not be sufficiently accretive to cash distributions per common unit without such conversion; however, it is possible that our general partner could exercise this reset election at a time when it is experiencing, or may be expected to experience, declines in the cash distributions it receives related to its incentive distribution rights and may therefore desire to be issued our Class B units, which are entitled to receive cash distributions from us on the same priority as our common units, rather than retain the right to receive incentive distributions based on the initial target distribution levels. As a result, a reset election may cause our common unitholders to experience dilution in the amount of cash distributions that they would have otherwise received had we not issued new Class B units to our general partner in connection with resetting the target distribution levels related to our general partner’s incentive distribution rights.

Holders of our common units have limited voting rights and are not entitled to elect our general partner or the board of directors of its general partner.

Unlike the holders of common stock in a corporation, unitholders have only limited voting rights on matters affecting our business and, therefore, limited ability to influence management’s decisions regarding our business. Unitholders will not elect our general partner, its general partner or the members of its board of directors, and will have no right to elect our general partner, its general partner or its board of directors on an annual or other continuing basis. The board of directors of EV Management is chosen by EnerVest, the sole member of EV Management. Furthermore, if the unitholders were dissatisfied with the performance of our general partner, they will have only a limited ability to remove our general partner. As a result of these limitations, the price at which the common units will trade could be diminished because of the absence or reduction of a takeover premium in the trading price.

Even if holders of our common units are dissatisfied, they will have difficulty removing our general partner without its consent.

The vote of the holders of at least 66 2/3% of all outstanding units voting together as a single class is required to remove the general partner. EnerVest owns and controls our general partner, and as of February 15, 2017, officers and directors of EV Management owned an aggregate of 10.5% of our outstanding common units. Accordingly, it may be difficult for holders of our common units to remove our general partner.

Our partnership agreement restricts the voting rights of unitholders owning 20% or more of our common units.

Unitholders’ voting rights are further restricted by the partnership agreement provision providing that any units held by a person that owns 20% or more of any class of units then outstanding, other than our general partner, its affiliates, their transferees and persons who acquired such units with the prior approval of the board of directors of our general partner, cannot vote on any matter. Our partnership agreement also contains provisions limiting the ability of unitholders to call meetings or to acquire information about our operations, as well as other provisions limiting the unitholders’ ability to influence the manner or direction of management.

Control of our general partner may be transferred to a third party without unitholder consent.

Our general partner may transfer its general partner interest to a third party in a merger or in a sale of all or substantially all of its assets without the consent of the unitholders. Furthermore, our partnership agreement does not restrict the ability of the owners of our general partner or EV Management, from transferring all or a portion of their respective ownership interest in our general partner or EV Management to a third party. The new owners of our general partner or EV Management would then be in a position to replace the board of directors and officers of EV Management with its own choices and thereby influence the decisions taken by the board of directors and officers.

We may issue additional units without your approval, which would dilute your existing ownership interests.

Our partnership agreement does not limit the number of additional limited partner interests that we may issue at any time without the approval of our unitholders. The issuance by us of additional common units or other equity securities of equal or senior rank will have the following effects:

We have the right to borrow to make distributions. Repayment of these borrowings will decrease cash available for future distributions.

Our partnership agreement allows us to borrow to make distributions. We may make short term borrowings under our credit facility, which we refer to as working capital borrowings, to make distributions. The primary purpose of these borrowings would be to mitigate the effects of short term fluctuations in our working capital that would otherwise cause volatility in our quarter to quarter distributions.

Our partnership agreement requires that we distribute all of our available cash, which could limit our ability to grow our reserves and production and service our debt obligations.

Our partnership agreement provides that we will distribute all of our available cash to our unitholders each quarter. As a result, we will be dependent on the issuance of additional common units and other partnership securities and borrowings to finance our growth. A number of factors will affect our ability to issue securities and borrow money to finance growth, as well as the costs of such financings, including:

Our general partner has a limited call right that may require you to sell your units at an undesirable time or price.

If at any time our general partner and its affiliates own more than 80% of our common units, our general partner will have the right, but not the obligation, which it may assign to any of its affiliates or to us, to acquire all, but not less than all, of the common units held by unaffiliated persons at a price not less than their then current market price. As a result, you may be required to sell your common units at an undesirable time or price and may not receive any return on your investment. You may also incur a tax liability upon a sale of your units.

Your liability may not be limited if a court finds that unitholder action constitutes control of our business.

A general partner of a partnership generally has unlimited liability for the obligations of the partnership, except for those contractual obligations of the partnership that are expressly made without recourse to the general partner. Our partnership is organized under Delaware law and we conduct business in a number of other states. The limitations on the liability of holders of limited partner interests for the obligations of a limited partnership have not been clearly established in some of the other states in which we do business. You could be liable for any and all of our obligations as if you were a general partner if:

Unitholders may have liability to repay distributions that were wrongfully distributed to them.

Under certain circumstances, unitholders may have to repay amounts wrongfully returned or distributed to them. Under Section 17–607 of the Delaware Revised Uniform Limited Partnership Act, we may not make a distribution to you if the distribution would cause our liabilities to exceed the fair value of our assets. Delaware law provides that for a period of three years from the date of the impermissible distribution, limited partners who received the distribution and who knew at the time of the distribution that it violated Delaware law will be liable to the limited partnership for the distribution amount. Substituted limited partners are liable for the obligations of the assignor to make contributions to the partnership that are known to the substituted limited partner at the time it became a limited partner and for unknown obligations if the liabilities could be determined from the partnership agreement. Liabilities to partners on account of their partnership interest and liabilities that are non–recourse to the partnership are not counted for purposes of determining whether a distribution is permitted.

If we distribute cash from capital surplus, which is analogous of a return of capital, our minimum quarterly distribution rate will be reduced proportionately, and the distribution thresholds after which the incentive distribution rights entitle our general partner to an increased percentage of distributions will be proportionately decreased.

Our cash distribution will be characterized as coming from either operating surplus or capital surplus. Operating surplus generally means amounts we receive from operating sources, such as sales of our production, less operating expenditures, such as production costs and taxes, and less estimated maintenance capital, which are generally amounts we estimate we will need to spend in the future to maintain our production levels over the long term. Capital surplus generally means amounts we receive from non–operating sources, such as sales of properties and issuances of debt and equity securities. Cash representing capital surplus, therefore, is analogous to a return of capital. Distributions of capital surplus are made to our unitholders and our general partner in proportion to their percentage interests in us, or 98 percent to our unitholders and two percent to our general partner, and will result in a decrease in our minimum quarterly distribution and a lower threshold for distributions on the incentive distribution rights held by our general partner.

Our partnership agreement allows us to add to operating surplus up to two times the amount of our most recent minimum quarterly distribution. As a result, a portion of this amount, which is analogous to a return of capital, may be distributed to the general partner and its affiliates, as holders of incentive distribution rights, rather than to holders of common units as a return of capital.

If we fail to maintain an effective system of internal controls, we may not be able to accurately report our financial results or prevent fraud. As a result, current and potential unitholders could lose confidence in our financial reporting, which would harm our business and the trading price of our units.

Effective internal controls are necessary for us to provide reliable financial reports, prevent fraud and operate successfully as a public company. If we cannot provide reliable financial reports or prevent fraud, our reputation and operating results would be harmed. We cannot be certain that our efforts to maintain our internal controls will be successful, that we will be able to maintain adequate controls over our financial processes and reporting in the future or that we will be able to continue to comply with our obligations under Section 404 of the Sarbanes-Oxley Act of 2002. Any failure to maintain effective internal controls, or difficulties encountered in implementing or improving our internal controls, could harm our operating results or cause us to fail to meet our reporting obligations. Ineffective internal controls could also cause investors to lose confidence in our reported financial information, which would likely have a negative effect on the trading price of our units.

Tax Risks to Common Unitholders

Our tax treatment depends on our status as a partnership for federal income tax purposes and not being subject to a material amount of entity–level taxation by individual states. If the Internal Revenue Service treats us as a corporation or we become subject to a material amount of entity-level taxation for state tax purposes, it would reduce the amount of cash available for distribution to our unitholders.

The anticipated after–tax economic benefit of an investment in our common units depends largely on our being treated as a partnership for U.S. federal income tax purposes. We have not requested, and do not plan to request, a ruling from the Internal Revenue Service, which we refer to as the IRS, on this or any other tax matter affecting us.

If we were treated as a corporation for U.S. federal income tax purposes, we would pay federal income tax on our taxable income at the corporate tax rate, which is currently a maximum of 35%, and would likely pay state income tax at varying rates. Distributions to you would generally be taxed again as corporate distributions, and no income, gains, losses or deductions would flow through to you. Because a tax would be imposed upon us as a corporation, our cash available for distribution to you would be substantially reduced. Therefore, treatment of us as a corporation would result in a material reduction in the anticipated cash flows and after–tax return to the unitholders, likely causing a substantial reduction in the value of our common units.

Current law may change so as to cause us to be treated as a corporation for U.S. federal income tax purposes or otherwise subject us to entity–level taxation. In addition, because of widespread state budget deficits and other reasons, several states are evaluating ways to subject partnerships to entity–level taxation through the imposition of state income, franchise and other forms of taxation. For example, in Texas, we are now subject to an entity level tax at a maximum effective rate of 0.7% on the portion of our income that is apportioned to Texas. Imposition of such a tax on us by Texas, or any other state, will reduce the cash available for distribution to a unitholder.

The partnership agreement provides that if a law is enacted or existing law is modified or interpreted in a manner that subjects us to taxation as a corporation or otherwise subjects us to entity-level taxation for federal, state or local income tax purposes, the minimum quarterly distribution amount and the target distribution levels will be adjusted to reflect the impact of that law on us.

An IRS contest of our U.S. federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest will reduce our cash available for distribution to our unitholders.

We have not requested a ruling from the IRS with respect to our treatment as a partnership for federal income tax purposes or any other matter affecting us. It may be necessary to resort to administrative or court proceedings to sustain some or all of our counsel’s conclusions or the positions we take. A court may not agree with all of our counsel’s conclusions or positions we take. Any contest with the IRS may materially and adversely impact the market for our common units and the price at which they trade. In addition, costs incurred in any contest with the IRS will be borne indirectly by our unitholders and our general partner because the costs will reduce our cash available for distribution.

You may be required to pay taxes on income from us even if you do not receive any cash distributions from us.

Because our unitholders will be treated as partners to whom we will allocate taxable income which could be different in amount than the cash we distribute, you will be required to pay any federal income taxes and, in some cases, state and local income taxes on your share of our taxable income even if you receive no cash distributions from us. You may not receive cash distributions from us equal to your share of our taxable income or even equal to the tax liability that results from that income.

Tax gain or loss on disposition of common units could be more or less than expected.

If you sell your common units, you will recognize a gain or loss equal to the difference between the amount realized and your tax basis in those common units. Prior distributions to you in excess of the total net taxable income you were allocated for a common unit, which decreased your tax basis in that common unit, will, in effect, become taxable income to you if the common unit is sold at a price greater than your tax basis in that common unit, even if the price is less than your original cost. A substantial portion of the amount realized, whether or not representing gain, may be ordinary income. In addition, if you sell your units, you may incur a tax liability in excess of the amount of cash you receive from the sale.

Tax–exempt entities and foreign persons face unique tax issues from owning common units that may result in adverse tax consequences to them.

Investment in common units by tax–exempt entities, such as individual retirement accounts (known as IRAs), other retirement plans and non–U.S. persons raises issues unique to them. For example, virtually all of our income allocated to organizations that are exempt from federal income tax, including IRAs and other retirement plans, will be unrelated business taxable income and will be taxable to them. Distributions to non–U.S. persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non–U.S. persons will be required to file U.S. federal tax returns and pay tax on their share of our taxable income.

We will treat each purchaser of our common units as having the same tax benefits without regard to the actual common units purchased. The IRS may challenge this treatment, which could adversely affect the value of the common units.

Because we cannot match transferors and transferees of common units and because of other reasons, we will take depreciation and amortization positions that may not conform to all aspects of existing Treasury regulations. A successful IRS challenge to those positions could adversely affect the amount of tax benefits available to you. It also could affect the timing of these tax benefits or the amount of gain from the sale of common units and could have a negative impact on the value of our common units or result in audit adjustments to your tax returns.

The sale or exchange of 50% or more of our capital and profits interests during any twelve–month period will result in the termination of our partnership for federal income tax purposes.

We will be considered to have terminated our partnership for federal income tax purposes if there is a sale or exchange of 50% or more of the total interests in our capital and profits within a twelve–month period. For example, an exchange of 50% of our capital and profits could occur if, in any twelve–month period, holders of our common units sell at least 50% of the interests in our capital and profits. Our termination would, among other things, result in the closing of our taxable year for all unitholders and could result in a deferral of depreciation deductions allowable in computing our taxable income.

Unitholders may be subject to state and local taxes and tax return filing requirements in states where they do not live as a result of investing in our common units.

In addition to federal income taxes, you will likely be subject to other taxes, including Medicare, state and local taxes, unincorporated business taxes and estate, inheritance or intangible taxes that are imposed by the various jurisdictions in which we do business or own property, even if you do not live in any of those jurisdictions. You will likely be required to file state and local income tax returns and pay state and local income taxes in some or all of these jurisdictions. Further, you may be subject to penalties for failure to comply with those requirements. We own assets and do business in the states of Texas, Louisiana, Oklahoma, Arkansas, New Mexico, Colorado, Kansas, Michigan, Ohio, West Virginia and Pennsylvania. Each of these states, other than Texas, currently imposes a personal income tax. As we make acquisitions or expand our business, we may own assets or do business in additional states that impose a personal income tax. It is your responsibility to file all U.S. federal, foreign, state and local tax returns.

The tax treatment of publicly traded partnerships or an investment in our common units could be subject to potential legislative, judicial or administrative changes and differing interpretations, possibly on a retroactive basis.

The present federal income tax treatment of publicly traded partnerships, including us, or an investment in our common units may be modified by legislative, judicial or administrative changes and differing interpretations at any time. Specifically, from time to time, members of Congress propose and consider substantive changes to the existing federal income tax laws that affect publicly traded partnerships. If successful, such a proposal could eliminate the qualifying income exception to the treatment of all publicly traded partnerships as corporations upon which we rely for our treatment as a partnership for U.S. federal income tax purposes. In addition, it is anticipated that the Trump administration will pass tax reform, and it is possible that such legislation could negatively impact our U.S. federal income taxation. Any modification to the U.S. federal income tax laws may be applied retroactively and could make it more difficult or impossible for us to meet the exception for certain publicly traded partnerships to be treated as partnerships for U.S. federal income tax purposes. We are unable to predict whether any of these changes or other proposals will ultimately be enacted. Any such changes could negatively impact the value of an investment in our common units.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.

ITEM 2. PROPERTIES

Information regarding our properties is contained in “Item 1. Business — Oil and Natural Gas Producing Activities and — Our Oil and Natural Gas Data” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” contained herein.

ITEM 3. LEGAL PROCEEDINGS

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements, and no amounts have been accrued at December 31, 2016.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

PART II

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED UNITHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

Our common units are traded on the NASDAQ Global Market under the symbol “EVEP.” At the close of business on February 15, 2017, based upon information received from our transfer agent and brokers and nominees, we had 351 common unitholders of record. This number does not include owners for whom common units may be held in “street” names.

The following table sets forth the range of the daily high and low sales prices per common unit and cash distributions to common unitholders for 2016 and 2015:

_____________

Cash Distributions to Unitholders

We have suspended cash distributions to unitholders in order to conserve cash and improve our liquidity. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants contained in our credit agreement. We are currently in compliance with all of the covenants contained in the most recent ninth amendment of our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent Ninth Amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions. There is no assurance as to the future cash distributions since they are dependent upon future earnings, cash flows, capital requirements, financial condition and other factors. Our credit agreement prohibits us from making cash distributions if any potential default or event of default, as defined in the credit agreement, occurs or would result from the cash distribution.

Our partnership agreement requires that, within 45 days after the end of each quarter, we distribute all of our available cash (as defined in our partnership agreement) to unitholders of record on the applicable record date. The amount of available cash generally is all cash on hand at the end of the quarter:

Working capital borrowings are borrowings used solely for working capital purposes or to pay distributions to unitholders.

Our general partner is entitled to 2% of all quarterly distributions that we make prior to our liquidation. Our general partner has the right, but not the obligation, to contribute a proportionate amount of capital to us to maintain its current general partner interest. The general partner’s initial 2% interest in these distributions will be reduced if we issue additional units in the future and our general partner does not contribute a proportionate share of capital to us to maintain its 2% general partnership interest. When we issued common units in the past, our general partner contributed to us an amount of cash necessary to maintain its 2% interest.

Our general partner also holds IDRs that entitle it to receive increasing percentages, up to a maximum of 25%, of the cash we distribute from operating surplus (as defined in our partnership agreement) in excess of the minimum quarterly distribution rate per unit per quarter. The maximum distribution percentage of 25% includes distributions paid to our general partner on its 2% general partner interest and assumes that our general partner maintains its general partner interest at 2%. The maximum distribution percentage of 25% does not include any distributions that our general partner may receive on common units that it owns. For additional information on our distributions, please see Note 11 of the Notes to Consolidated Financial Statements in “Item 8. Financial Statements and Supplementary Data.”

Our partnership agreement requires that we make distributions of available cash from operating surplus for any quarter in the following manner:

Our general partner is entitled to incentive distributions if the amount we distribute with respect to one quarter exceeds specified target levels shown below:

Unregistered Sales of Equity Securities

None.

Issuer Purchases of Equity Securities

None.

ITEM 6. SELECTED FINANCIAL DATA

The following table shows selected financial data for the periods and as of the dates indicated. The selected financial data are derived from our financial statements. With the sale of our interest in Cardinal in October 2014 and UEO in June 2015, we no longer operate in the midstream segment, and we have reclassified our consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations. Accordingly, in the consolidated statements of operations, amounts previously included in “Equity in income of unconsolidated affiliates” have been reclassified to “Income from discontinued operations.” The selected financial data should be read in conjunction with “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and “Item 8. Financial Statements and Supplementary Data,” both contained herein.

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” contained herein.

OVERVIEW

We are a Delaware limited partnership formed in April 2006 by EnerVest. Our general partner is EV Energy GP, a Delaware limited partnership, and the general partner of our general partner is EV Management, a Delaware limited liability company.

As of December 31, 2016, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, Central Texas (which includes the Austin Chalk area), the Monroe Field in Northern Louisiana, the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin. As of December 31, 2016, we had estimated net proved reserves of 12.6 MMBbls of oil, 575.3 Bcf of natural gas and 33.4 MMBbls of natural gas liquids, or 851.2 Bcfe, and a standardized measure of $371.1 million.

Current Price Environment

Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile. In late 2014, prices for oil, natural gas and natural gas liquids declined precipitously, and prices remained low through 2015 and most of 2016. While prices showed some improvement during the second half of 2016 and the beginning of 2017, they have continued to fluctuate.

Factors contributing to lower oil prices include real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; lower forecasted levels of global economic growth combined with excess global supply; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the U.S. dollar in international currency markets. Factors contributing to lower natural gas prices include increased supplies of natural gas due to greater exploration and development activities; higher levels of natural gas in storage; and competition from other energy sources. Prices for natural gas liquids generally correlate to the price of oil and, accordingly, prices remain lower than historical levels and are likely to continue to directionally follow the market for oil.

In 2016, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.

As specified by the SEC, the prices for oil, natural gas and natural gas liquids used to calculate our reserves were the average prices during the year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved reserves at December 31, 2016 were $42.75 per Bbl of oil and $2.481 per MMBtu of natural gas, which is significantly lower than current forward strip prices. Had we used the forward strip prices at December 31, 2016 through December 2029, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 111% higher and that our reserves on an Mcfe basis would have been approximately 50% higher than our reserves calculated using SEC prices.

Our Response to the Current Price Environment

In 2016, in response to continued lower prices, we took a number of actions to preserve our liquidity and financial flexibility, including:

As a result of the steps above, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:

During 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first three quarters of 2016. The board of directors also elected to suspend distributions for the fourth quarter of 2016. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than in previous years. The board of directors continues to evaluate the distribution on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution.

In December 2016, we sold a portion of our Barnett Shale natural gas properties for $52.1 million (before post-closing adjustments), which proceeds were deposited into a 1031 ‘like-kind' exchange account. On January 31, 2017, we acquired a 5.8% working interest in 9,151 gross acres (529 net acres) in Karnes County, TX for $58.7 million (before post-closing purchase price adjustments) with the proceeds and $6.6 million of borrowings under our credit facility (the “Eagle Ford Acquisition”). Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.

Business Environment

One of our primary business objectives is to generate sufficient excess cash flow that will allow us to reinstate a stable distribution, which we will be able to grow over time. Prior to reinstating distributions, we will ensure that we are, and will continue to be, in compliance with the covenants in our credit agreement. We are currently in compliance with all of the covenants contained in our credit agreement and, at current forward prices, expect to be in compliance through the end of 2017. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we may have a total debt to EBITDAX ratio higher than the level prescribed in the most recent Ninth Amendment of our credit agreement. Absent a rebound in commodity prices, we currently project that we will not be in compliance with our leverage covenant at the end of the first quarter of 2018, and this may require us to make payments on our debt facilities or require us to work with our bank syndicate to amend our credit agreement. Our inability to amend our credit agreement or otherwise comply with the covenants in our credit agreement could have a material, adverse effect on our business, including our ability to resume and sustain distributions. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

In order to mitigate the impact of these lower prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. Although we have entered into derivative contracts covering a portion of our future production through March 2018, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future. We have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended period of depressed commodity prices would alter our acquisition and development plans, adversely affect our growth strategy and our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions, which may require us to further delay our ability to reinstate our quarterly distribution amount.

The primary factors affecting our production levels are capital availability, our ability to make accretive acquisitions, the success of our drilling program and our inventory of drilling prospects. In addition, as initial reservoir pressures are depleted, production from our wells decreases. We attempt to overcome this natural decline through a combination of drilling and acquisitions. Our future growth will depend on our ability to continue to add reserves through drilling and acquisitions in excess of production. We will maintain our focus on the costs to add reserves through drilling and acquisitions as well as the costs necessary to produce such reserves. Our ability to add reserves through drilling is dependent on our capital resources and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Any delays in drilling, completion or connection to gathering lines of our new wells will negatively impact our production, which may have an adverse effect on our revenues and, as a result, cash available for distribution.

We focus our efforts on increasing our reserves and production while controlling costs at a level that is appropriate for long–term operations. Our future cash flows from operations are dependent upon our ability to manage our overall cost structure.

In 2016, we spent significantly less capital drilling wells relative to previous years. As a result, we saw our total production decline throughout the year, when adjusting for the oil and natural gas properties that we acquired on October 1, 2015. For 2017, we plan to spend $30 - $45 million of capital in an effort to keep our production flat. We will continue monitoring the ongoing commodity price environment and expect to retain the financial flexibility to adjust plans in response to market conditions as needed.

Critical Accounting Policies

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with U.S. generally accepted accounting principles. The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

Our critical accounting policies are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We believe that the following are the critical accounting policies used in the preparation of our consolidated financial statements.

Oil and Natural Gas Properties

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs, certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

No gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate. Sales proceeds are credited to the carrying value of the properties.

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Independent reserve engineers prepare our reserve estimates at the end of each year.

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense. Our reserves are also the basis of our supplemental oil and natural gas disclosures.

Accounting for Derivatives

We use derivatives to hedge against the variability in cash flows associated with the forecasted sale of our anticipated future oil, natural gas and natural gas liquids production. We generally hedge a substantial, but varying, portion of our anticipated production for the next 12 – 36 months. We do not use derivatives for trading purposes. We have elected not to apply hedge accounting to our derivatives. Accordingly, we carry our derivatives at fair value on our consolidated balance sheet, with the changes in the fair value included in our consolidated statement of operations in the period in which the change occurs. Our current results of operations would potentially have been significantly different had we elected and qualified for hedge accounting on our derivatives.

In determining the amounts to be recorded, we are required to estimate the fair values of the derivatives. We base our estimates of fair value upon various factors that include closing prices on the NYMEX, volatility, the time value of options, our credit worthiness and the credit worthiness of the counterparties to our derivative instruments. These pricing and discounting variables are sensitive to market volatility as well as changes in future price forecasts and interest rates.

Goodwill

Goodwill is an asset representing the future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. In accounting for a business combination, the purchase price is allocated to the identifiable assets and liabilities based upon the estimated fair values as of the acquisition date. Goodwill is the excess of the purchase price over the estimated fair values of the assets acquired net of the liabilities assumed in the acquisition. Goodwill is not amortized, but is evaluated for impairment at the reporting unit level.

We have the option of performing either a qualitative or quantitative assessment to determine if impairment may have occurred. If the qualitative assessment indicates that it is more likely than not that the fair value of our reporting unit is less than its carrying amount, then we would be required to perform the two step impairment test.

Under the first step in the impairment test, we compare the fair value of our reporting unit with its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, the second step of the goodwill impairment test is performed. Under the second step in the impairment test, the implied fair value of goodwill is compared with its carrying amount. The implied fair value of goodwill is calculated by subtracting the estimated fair values of our reporting unit’s assets net of liabilities from the fair value of our reporting unit. If the carrying amount of goodwill exceeds its implied fair value, an impairment loss shall be recognized in an amount equal to that excess.

We determine the fair value of the reporting unit using a combination of the market approach and the income approach. Under the market approach, the fair value is based on the quoted market price for our common units adjusted for a control premium, which is the premium over current market price a market participant may be willing to pay to obtain the synergies and other benefits that control would provide. Under the income approach, the fair value was based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of the fair value include estimates of the appropriate control premium, future prices, production costs, development expenditures, anticipated production, appropriate risk–adjusted discount rates and other relevant data. Given the nature of these estimates and their application to specific assets and liabilities and time frames, it is not possible to reasonably quantify the impact of changes in these assumptions.

Accounting for Asset Retirement Obligations

We have significant obligations to remove tangible equipment and facilities and restore land at the end of oil and natural gas production operations. Our removal and restoration obligations are primarily associated with site reclamation, dismantling facilities and plugging and abandoning wells. Estimating the future restoration and removal costs is difficult and requires management to make estimates and judgments because most of the removal obligations are many years in the future and contracts and regulations often have vague descriptions of what constitutes removal. Asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

We record an asset retirement obligation (“ARO”) and capitalize the asset retirement cost in oil and natural gas properties in the period in which the retirement obligation is incurred based upon the fair value of an obligation to perform site reclamation, dismantle facilities or plug and abandon wells. After recording these amounts, the ARO is accreted to its future estimated value using an assumed cost of funds and the additional capitalized costs are depreciated on a unit–of–production basis.

Inherent in the present value calculation are numerous assumptions and judgments including the ultimate settlement amounts, inflation factors, credit adjusted discount rates, timing of settlement and changes in the legal, regulatory, environmental and political environments. To the extent future revisions of these assumptions impact the present value of the existing asset retirement obligation, a corresponding adjustment is made to the oil and natural gas property balance.

Revenue Recognition

Oil, natural gas and natural gas liquids revenues are recognized when production is sold to a purchaser at fixed or determinable prices, when delivery has occurred and title has transferred and collectibility of the revenue is reasonably assured. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

There are two principal accounting practices to account for natural gas imbalances. These methods differ as to whether revenue is recognized based on the actual sale of natural gas (sales method) or an owner's entitled share of the current period's production (entitlement method). We follow the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which we are entitled based on our working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where we have taken less than our share of production.

We own and operate a network of natural gas gathering systems in the Monroe Field in Northern Louisiana which gather and transport owned natural gas and a small amount of third party natural gas to intrastate, interstate and local distribution pipelines. Natural gas gathering and transportation revenue is recognized when the natural gas has been delivered to a custody transfer point.

RESULTS OF OPERATIONS

Year Ended December 31, 2016 Compared with the Year Ended December 31, 2015

Net loss for 2016 was $242.9 million compared with net income of $21.3 million for 2015. The significant factors in this change were (i) a $255.5 million decrease in income from discontinued operations; (ii) a $114.1 million unfavorable change in gain (loss) on derivatives; partially offset by (iii) a $65.9 million decrease in impairment of goodwill; and (iv) a $23.7 million increase in gain on early extinguishment of debt.

Oil, natural gas and natural gas liquids revenues for 2016 totaled $182.7 million, an increase of $7.6 million compared with 2015. This was the result of increases of $18.5 million related to increased oil, natural gas and natural gas liquids production as a result of the October 2015 acquisitions offset by decreases of $10.9 million related to lower prices for oil, natural gas and natural gas liquids.

Lease operating expenses for 2016 increased $3.7 million compared with 2015 as the result of $9.9 million from increased oil and natural gas production offset by $6.2 million from a lower cost per Mcfe. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.46 in 2016 compared with $1.56 in 2015.

Dry hole and exploration costs for 2016 decreased $3.0 million compared with 2015 as a result of our decreased drilling program during 2016.

Production taxes for 2016 increased $0.6 million compared with 2015 due to higher oil, natural gas and natural gas liquids revenues. Production taxes for 2016 were $0.10 per Mcfe compared with $0.11 per Mcfe for 2015.

Depreciation, depletion and amortization (“DD&A”) for 2016 increased $13.2 million compared with 2015 due to $11.5 million of increased oil and natural gas production combined with $1.7 million from a higher average DD&A rate per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for 2016 was $1.69 per Mcfe compared with $1.66 per Mcfe for 2015.

General and administrative expenses for 2016 totaled $33.6 million, a decrease of $5.4 million compared with 2015. This decrease is primarily the result of (i) $5.4 million of lower equity compensation costs, of which $2.3 million related to the accelerated vesting of the phantom units of a former officer in 2015; (ii) $1.3 million of decreased compensation costs, of which $0.8 million related to the vesting of our phantom units under our equity compensation plan; partially offset by (iii) $1.7 million of higher fees paid to EnerVest under the omnibus agreement related to our October 2015 acquisition. General and administrative expenses were $0.48 per Mcfe in 2016 compared with $0.62 per Mcfe in 2015.

As a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids and the disposition of oil and gas properties, we incurred impairment charges of $131.3 million and $136.7 million in 2016 and 2015, respectively. Of these amounts, $89.5 million and $86.9 million in 2016 and 2015, respectively, related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. The $89.5 million of impairment for 2016 related to oil and natural gas properties in the Barnett Shale which were sold during December 2016 (see Note 5). Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data. The remainder of the impairment charges in 2016 consisted of $41.8 million of leasehold impairments, of which $35.8 million related to a change in our development plans for acreage in the Appalachian Basin, primarily in the Utica Shale. The remainder of the impairment charges in 2015 consisted of $49.8 million of leasehold impairments, of which $49.2 million related to a change in our development plans for acreage in the Utica Shale.

In conjunction with our October 2015 acquisitions of oil and natural gas properties, we recorded $65.9 million of goodwill. As of December 31, 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We determined the fair value of the reporting unit using a combination of the market approach and the income approach. Significant assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk–adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill.

In 2015, we recognized a gain of $0.6 million on the sale of certain non–core oil and natural gas properties.

Loss on derivatives, net was $36.0 million for 2016 compared with a gain on derivatives, net of $78.1 million for 2015. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at December 31, 2016 for oil averaged $56.19 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at December 31, 2016 for natural gas averaged $3.61 per MmBtu compared with $2.49 at December 31, 2015. The 12 month forward price at December 31, 2015 for oil averaged $40.45 per Bbl compared with $56.46 per Bbl at December 31, 2014, and the 12 month forward price at December 31, 2015 for natural gas averaged $2.49 per MmBtu compared with $3.03 at December 31, 2014.

Interest expense for 2016 decreased $7.8 million compared with 2015 due to $9.4 million from a lower weighted average long-term debt balance, partially offset by $0.1 million from a higher weighted average effective interest rate and the write-off of $1.5 million of loan costs due to the reduction in the borrowing base and the redemption of the senior notes due April 2019.

In 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our Notes due April 2019 for $35.0 million. In 2015, we recognized a $24.0 million gain on the early extinguishment of debt as we redeemed $74.0 million of our Notes due April 2019 for $50.0 million.

In 2016, we recorded approximately $2.4 million of tax benefits as a result of tax refunds and lower taxes. In December 2015, we converted our wholly-owned subsidiary Belden and Blake Corporation (“Belden”) from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion.

Income from discontinued operations was $255.5 million in 2015. Included in 2015 was the $246.7 million gain on the sale of UEO.

Year Ended December 31, 2015 Compared with the Year Ended December 31, 2014

Net income for 2015 was $21.3 million compared with $129.7 million for 2014. The significant factors in this change were (i) a $159.6 million decrease in oil, natural gas and natural gas liquids revenues; (ii) a $32.8 million decrease in gain on sale of oil and natural gas properties; (iii) a $65.9 million impairment of goodwill; (iv) a $22.7 million increase in impairment of oil and natural gas properties; and (v) a $21.6 million unfavorable change in gain (loss) on derivatives; offset by (v) a $148.0 million increase in income (loss) from discontinued operations; (vi) a $24.0 million gain on early extinguishment of debt and (vii) a $21.2 million decrease in operating costs and expenses (excluding impairment of oil and natural gas properties and impairment of goodwill).

Oil, natural gas and natural gas liquids revenues for 2015 totaled $175.1 million, a decrease of $159.6 million compared with 2014. This was the result of decreases of $159.8 million related to lower prices for oil, natural gas and natural gas liquids and $0.5 million from decreased oil production from our reduced capital spending program and natural decline offset by $0.7 million related to increased oil and natural gas production as a result of the October 2015 acquisitions.

Lease operating expenses for 2015 decreased $6.2 million compared with 2014 as the result of $6.6 million from a lower cost per Mcfe offset by $0.4 million from increased oil and natural gas production. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.56 in 2015 compared with $1.66 in 2014.

Dry hole and exploration costs for 2015 decreased $3.0 million compared with 2014 as a result of lower costs at certain of our oil and natural gas properties in the Appalachian Basin and the Austin Chalk.

Production taxes for 2015 decreased $5.2 million compared with 2014 due to lower oil, natural gas and natural gas liquids revenues. Production taxes for 2015 were $0.11 per Mcfe compared with $0.19 per Mcfe for 2014.

Depreciation, depletion and amortization (“DD&A”) for 2015 decreased $0.1 million compared with 2014 due to $0.5 million from a lower average DD&A rate per Mcfe offset by $0.4 million of increased oil and natural gas production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2014. DD&A for 2015 was $1.66 per Mcfe compared with $1.67 per Mcfe for 2014.

General and administrative expenses for 2015 totaled $39.0 million, a decrease of $6.0 million compared with 2014. This decrease is primarily the result of (i) $7.3 million of lower equity compensation costs; (ii) $1.0 million of costs incurred in 2014 related to the departure of a former officer; and (iii) $0.9 million of decreased compensation costs related to the vesting of our phantom units issued under our equity based compensation plan; offset by (iv) $2.1 million of higher fees paid to EnerVest under the omnibus agreement, (v) $0.8 million of increased audit and reserve fees as a result of our October 2015 acquisitions; and (vi) $0.9 million of due diligence costs related to our October 2015 acquisitions. General and administrative expenses were $0.62 per Mcfe in 2015 compared with $0.71 per Mcfe in 2014.

As a result of a reduction in estimated future net cash flows primarily caused by the decrease in prices for oil, natural gas and natural gas liquids, we incurred impairment charges of $136.7 million and $114.0 million in 2015 and 2014, respectively. Of these amounts, $86.9 million and $103.1 million in 2015 and 2014, respectively, related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk–adjusted discount rates and other relevant data. The remainder of the impairment charges in 2015 consisted of $49.8 million of leasehold impairments, of which $49.2 million related to a change in our development plans for acreage in the Utica Shale. The remainder of the impairment charges in 2014 consisted of $10.7 million of leasehold impairment charges and $0.2 million of an impairment charge to write down assets held for sale to their fair value.

In conjunction with our October 2015 acquisitions of oil and natural gas properties, we recorded $65.9 million of goodwill. As of December 31, 2015, we determined that the carrying amount of goodwill was impaired due to the continued decline in oil, natural gas and natural gas liquids prices. We determined the fair value of the reporting unit using a combination of the market approach and the income approach. Significant assumptions associated with the calculation of the fair value included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk–adjusted discount rates and other relevant data. We then determined the implied fair value of goodwill by subtracting the estimated fair values of the reporting unit’s assets net of liabilities from the fair value of the reporting unit. As the carrying amount of the goodwill exceeded the implied fair value of the goodwill, we recognized a $65.9 million impairment loss for the difference between the carrying amount and the implied fair value of goodwill.

In 2015, we recognized a gain of $0.6 million on the sale of certain non–core oil and natural gas properties. In 2014, we recognized a $31.8 million gain on the sale of oil and natural gas properties in the Eagle Ford and a $1.5 million gain on the sale of oil and natural gas properties in the Utica Shale area of Ohio.

Gain on derivatives, net was $78.1 million for 2015 compared with $99.7 million for 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at December 31, 2015 for oil averaged $40.45 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at December 31, 2015 for natural gas averaged $2.49 per MmBtu compared with $3.03 at December 31, 2014. The 12 month forward price at December 31, 2014 for oil averaged $56.46 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at December 31, 2014 for natural gas averaged $3.03 per MmBtu compared with $4.19 at December 31, 2013.

Interest expense for 2015 decreased $2.2 million compared with 2014 due to $10.6 million from a higher weighted effective average interest rate and $5.7 million from a decrease in capitalized interest offset by $18.5 million from a lower weighted average long–term debt balance.

In 2015, we recognized a $24.0 million gain on the early extinguishment of debt as we redeemed $74.0 million of our Notes due April 2019 for $50.0 million.

In December 2015, we converted Belden from a corporation into a single member limited liability company. As a result, the $13.4 million of deferred taxes recorded in the acquisition of Belden were realized. The benefit was offset by an $11.7 million current tax liability for the estimated federal and state taxes based on the fair value of Belden as of the date of conversion.

Income from discontinued operations was $255.5 million for 2015 compared with $107.5 million in 2014. Included in 2015 and 2014 were the $246.7 million gain on the sale of UEO and the $92.1 million gain of the sale of Cardinal, respectively.

LIQUIDITY AND CAPITAL RESOURCES

Historically, our primary sources of liquidity and capital have been issuances of equity and debt securities, borrowings under our credit facility and cash flows from operations. Our primary uses of cash have been acquisitions of oil and natural gas properties and related assets, development of our oil and natural gas properties, distributions to our unitholders and general partner and working capital needs.

In 2016, in response to continued lower prices, we took a number of actions, including repurchasing outstanding senior notes, reducing capital spending and operating costs, suspending distributions on our common units and strategic divestitures of non-core assets, to preserve our liquidity and financial flexibility. As a result of these steps, as of December 31, 2016, we have over $205 million of liquidity between our borrowing base capacity, cash on hand and restricted cash. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:

For 2017, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility will be adequate to fund our capital budget and satisfy our short–term liquidity needs.

We may also utilize borrowings under our credit facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund our acquisitions and long–term liquidity needs. Our ability to complete future offerings of equity or debt securities and the timing of these offerings will depend upon various factors including prevailing market conditions and our financial condition.

Long–term Debt

As of December 31, 2016, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of December 31, 2016, the borrowing base was $450.0 million, and we had $265.0 million outstanding. We believe we will maintain sufficient short–term liquidity. However, should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity.

In April 2016, we entered into an amendment to our credit facility that eased leverage covenants and added an interest coverage ratio. Specifically, the amendment:

As of December 31, 2016, we have $343.3 million in aggregate principal amount outstanding of 8.0% senior notes due April 2019. As of December 31, 2016, the aggregate carrying amount of the senior notes due April 2019 was $341.9 million.

For additional information about our long–term debt, such as interest rates and covenants, please see “Item 8. Financial Statements and Supplementary Data” contained herein.

Cash and Cash Equivalents

At December 31, 2016, we had $5.6 million of cash and cash equivalents, which included $0.7 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

Restricted Cash

At December 31, 2016, we had $52.1 million of restricted cash, which represents proceeds from the Barnett Shale divestiture we deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code. In January 2017, these proceeds were used to fund, in part, the Eagle Ford Acquisition.

Counterparty Exposure

All of our derivative contracts are with major financial institutions who are also lenders under our credit facility. Should one of these financial counterparties not perform, we may not realize the benefit of some of our derivative contracts and we could incur a loss. As of December 31, 2016, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows

Operating Activities

Cash flows from operating activities provided $33.9 million and $141.3 million in 2016 and 2015, respectively. The significant factors in the change were $85.8 million of decreased cash settlements from our matured derivative contracts, an $11.7 million federal tax payment related to the conversion of an acquired corporation to a single member LLC and a $28.9 million change in working capital, primarily related to higher accounts receivable as a result of higher oil, natural gas and natural gas liquids production during 2016.

Cash flows from operating activities provided $141.3 million and $148.2 million in 2015 and 2014, respectively. The significant factors in the change were a $161.1 million decrease in our revenues offset by $135.3 million of increased cash settlements from our matured derivative contracts and the effects of our efforts to increase our financial flexibility through asset sales and accretive acquisitions.

Investing Activities

During 2016, cash flows used in investing activities from continuing operations totaled $9.8 million. This consisted of $52.1 million of restricted cash deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code and $15.3 million for additions to our oil and natural gas properties offset by $54.5 million from the sale of oil and natural gas properties and $3.0 million in cash settlements from acquired derivative contracts.

During 2015, cash flows used in investing activities from continuing operations totaled $280.4 million. This consisted of $250.4 million for acquisitions of oil and natural gas properties, $67.9 million for additions to our oil and natural gas properties offset by $33.8 million from the release of cash deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code, $2.6 million in cash settlements from acquired derivative contracts and $1.5 million in proceeds from the sales of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $572.2 million consisted of the proceeds from the sale of our interest in UEO.

During 2014, cash flows used in investing activities from continuing operations totaled $93.8 million, consisting of $102.8 million for additions to our oil and natural gas properties and an increase of $33.8 million related to cash deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code offset by $45.2 million in proceeds from the sale of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $47.0 million consisted of $161.1 million in proceeds from the sale of our interest in Cardinal offset by $114.1 million of additions to our investment in UEO.

Financing Activities

During 2016, we received $57.0 million from borrowings under our credit facility, repaid $57.0 million of borrowings under our credit facility, and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner. We also redeemed $82.7 million of our senior notes due April 2019 for $35.0 million.

During 2015, we repaid $561.0 million of borrowings under our credit facility with proceeds from the sale of our investment in UEO and the release of our restricted cash. We also redeemed $74.0 million of our senior notes due April 2019 for $50.0 million, received $295.0 million from borrowings under our credit facility, incurred loan costs of $4.1 million related to the amendments of our credit facility and paid distributions of $101.0 million to holders of our common units, phantom units and our general partner.

During 2014, we received $209.0 million from borrowings under our credit facility, and we repaid $159.0 million of borrowings under our credit facility. In addition, we paid distributions of $155.0 million to holders of our common units and phantom units and our general partner.

Capital Requirements

We currently expect spending in 2017 for additions to our oil and natural gas properties to be between $30 million and $45 million, an increase from the amounts spent in 2016. In addition, we spent $58.7 million (before post-closing purchase price adjustments) for the Eagle Ford Shale properties we acquired on January 31, 2017.

We expect to fund these amounts with cash on hand, restricted cash, proceeds from sales of assets, net cash flows generated from operations and borrowings under our credit facility.

We are actively engaged in the acquisition of oil and natural gas properties. We would expect to finance any significant acquisition of oil and natural gas properties in 2017 through the issuance of equity or debt securities.

Contractual Obligations

Our asset retirement obligations are not included in the table above given the uncertainty regarding the actual timing of such expenditures. The total amount of our asset retirement obligations at December 31, 2016 is $183.5 million.

Off–Balance Sheet Arrangements

In the normal course of business, we may enter into off-balance sheet arrangements that give rise to off-balance sheet obligations. As of December 31, 2016, we have entered into off–balance sheet arrangements which totaled $0.3 million.

RECENT ACCOUNTING STANDARDS

Please see “Item 8. Financial Statements and supplementary Data” contained herein for additional information.

FORWARD–LOOKING STATEMENTS

This Form 10–K contains forward–looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Exchange Act (each a “forward–looking statement”). These forward–looking statements relate to, among other things, the following:

We have based these forward–looking statements on our current assumptions, expectations and projections about future events.

The words “anticipate,” “believe,” “ensure,” “expect,” “if,” “intend,” “estimate,” “project,” “forecasts,” “predict,” “outlook,” “aim,” “will,” “could,” “should,” “would,” “may,” “likely” and similar expressions, and the negative thereof, are intended to identify forward–looking statements. These statements discuss future expectations, contain projections of results of operations or of financial condition or state other “forward–looking” information. We do not undertake any obligation to update or revise publicly any forward–looking statements, except as required by law. These statements also involve risks and uncertainties that could cause our actual results or financial condition to materially differ from our expectations in this Form 10–K including, but not limited to:

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A.

Our revenues, operating results, financial condition and ability to borrow funds or obtain additional capital depend substantially on prevailing prices for oil, natural gas and natural gas liquids. Declines in prices may materially adversely affect our financial condition, liquidity, ability to obtain financing and operating results. Lower prices also may reduce the amount of oil, natural gas or natural gas liquids that we can produce economically. A decline in prices could have a material adverse effect on the estimated value and estimated quantities of our reserves, our ability to fund our operations and our financial condition, cash flows, results of operations and access to capital. Historically, prices and markets have been volatile, with prices fluctuating widely, and they are likely to continue to be volatile.

ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

We are exposed to certain market risks that are inherent in our financial statements that arise in the normal course of business. We may enter into derivatives to manage or reduce market risk, but do not enter into derivatives for speculative purposes.

We do not designate these or future derivatives as hedges for accounting purposes. Accordingly, the changes in the fair value of these derivatives are recognized currently in earnings.

Commodity Price Risk

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, derivatives to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre–existing or anticipated sales of oil, natural gas and natural gas liquids.

We have entered into derivatives to hedge a portion of our anticipated production through March 2018. As of December 31, 2016, we have derivatives covering approximately 85% of our production attributable to our estimated net proved reserves through March 2018, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially. Please read the disclosures under “Our estimated reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves” in the “Risk Factors” section included in Item 1A.

The fair value of our oil and natural gas derivatives at December 31, 2016 was a liability of $22.6 million. A 10% change in prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our commodity contracts of approximately $17.4 million. Please see “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

Interest Rate Risk

Our floating rate credit facility and interest rate derivatives also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for 2016 would have increased by approximately $2.9 million. The fair value of our interest rate derivatives at December 31, 2016 was an asset of $0.2 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate derivatives of approximately $0.2 million. Please see “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including our Chief Executive Officer and Chief Financial Officer, is responsible for establishing and maintaining effective internal control over our financial reporting. Our internal control system was designed to provide reasonable assurance to our Management and Directors regarding the preparation and fair presentation of published financial statements. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that EV Energy Partners, L.P.’s internal control over financial reporting was effective as of December 31, 2016.

Deloitte & Touche LLP, our independent registered public accounting firm, has issued an attestation report on the effectiveness on our internal control over financial reporting as of December 31, 2016 which is included in “Item 8. Financial Statements and Supplementary Data” contained herein.