Harvest Oil & Gas Corp. - Annual Report: 2017 (Form 10-K)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10–K

For the fiscal year ended December 31, 2017

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 o NO þ

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 o 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 o

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 of this Form 10-K or any amendment to this Form 10–K. þ

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨

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, 2017 based on the closing price on the NASDAQ Global Market on June 30, 2017 was $27,781,981.

As of March 27, 2018, the registrant had 49,368,869 common units outstanding.

Documents Incorporated by Reference: None

Table of Contents 

GLOSSARY OF OIL AND NATURAL GAS TERMS

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

Bcf. One billion cubic feet of natural gas.

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

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 a producing 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 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 equivalent of natural gas, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas. 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 of natural gas, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

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 PUDs 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 PUDs 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 or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

Standardized measure. The standardized measure of discounted future net cash flows, or “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 of natural gas, determined using a ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

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 business activities are primarily conducted through wholly owned subsidiaries.

As of December 31, 2017, 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 Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin, the Monroe Field in Northern Louisiana and Karnes County, Texas (which includes the Eagle Ford Shale).

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, 2017:

The table below provides a reconciliation of PV–10 to the standardized measure at December 31, 2017 (dollars in millions):

Restructuring and Bankruptcy Proceedings under Chapter 11

As discussed under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations,” continued low oil and natural gas prices have had a significant adverse impact on our business, and, as a result of our financial condition, substantial doubt exists that we will be able to continue as a going concern.

On March 13, 2018, EVEP, EV Energy GP, EV Management and certain of EVEP’s wholly owned subsidiaries (each a “Debtor” and, collectively, the “Debtors”) entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) holders (collectively, the “Supporting Noteholders”) of approximately 70% of the 8.0% senior unsecured notes due April 2019 (the “Senior Notes”) issued pursuant to that certain indenture, dated as of March 22, 2011 (as amended, restated, supplemented or otherwise modified from time to time, the “Indenture”), among EVEP, EV Energy Finance Corp., each of the guarantors party thereto, and Delaware Trust Company, as indenture trustee (the “Notes Trustee”), that are signatories to the Restructuring Support Agreement; (ii) lenders (collectively, the “Supporting Lenders” and, together with the Supporting Noteholders, the “Supporting Parties”) under our reserve-based lending facility, by and among EVEP, EV Properties, L.P., JPMorgan Chase Bank, N.A., as administrative agent (the “Administrative Agent”), BNP Paribas and Wells Fargo, National Association, as co-syndication agents, the guarantors party thereto (the “credit facility”), and the lenders signatory thereto, constituting approximately 94% of the principal amount outstanding thereunder; (iii) EnerVest; and (iv) EnerVest Operating, L.L.C. (“EnerVest Operating” and, together with EnerVest, the “EnerVest Parties”). The Restructuring Support Agreement sets forth, subject to certain conditions, the commitment of the Debtors and the Consenting Creditors to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring”).

The prepackaged plan of reorganization (the “Plan”) which remains subject to confirmation by the Bankruptcy Court and other closing conditions, provides that, among other things, on the effective date of the Plan (the “Effective Date”), subject to the occurrence and completion of certain structuring steps:

On March 14, 2018, the Debtors commenced the solicitation of votes from the holders of the Senior Notes to accept or reject the Plan in accordance with the terms of the Restructuring Support Agreement.

On April 2, 2018, the Debtors commenced cases (the “Chapter 11 Cases”) under Chapter 11 of the United States Bankruptcy Code (the “Bankruptcy Code”) in the US Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”). The Debtors have filed motions with the Bankruptcy Court seeking operational and procedural relief, including joint administration of their Chapter 11 Cases. The Debtors have also filed a motion requesting that the Bankruptcy Court schedule a hearing to confirm the Plan. If the Plan is confirmed by the Bankruptcy Court and becomes effective, then the claims of the lenders under the credit facility and the holders of the Senior Notes will be discharged. There can be no assurance regarding the Partnership’s ability to obtain confirmation of the Plan or approval of other relief in the Chapter 11 Cases, the Bankruptcy Court’s rulings in the Chapter 11 Cases or the ultimate outcome of the Chapter 11 Cases in general.

As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases described above accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, which is subject to a 30 day grace period. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Partnership as a result of an event of default.

For the duration of the Restructuring and after the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with the Restructuring and Chapter 11 Cases. As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.

The Partnership expects to continue its operations without interruption during the pendency of the Chapter 11 Cases. See Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

Current Developments

NASDAQ Delisting

Our common units are traded on the NASDAQ Capital Market (the “NASDAQ”) under the symbol “EVEP.” On July 17, 2017, we received a letter from the NASDAQ notifying us that we were not in compliance with the NASDAQ Global Market’s rules that require the minimum bid price of our units to be at least $1.00 per share over a consecutive 30-trading-day period. On December 27, 2017, we applied to transfer from the NASDAQ Global Market to the NASDAQ Capital Market and requested an additional 180-day grace period to regain compliance with the NASDAQ Capital Market’s minimum bid price requirement because our common units have continued to trade below the $1.00 minimum closing bid price. In January 2018, the NASDAQ approved both the transfer and the extension of the 180-day grace period, which will end on July 16, 2018. This notice from the NASDAQ does not affect our business operations or trigger any default or other violation of our debt or other material obligations.

In connection with filing the Chapter 11 Cases, we expect to receive a notice from the NASDAQ stating that our units will be delisted from the NASDAQ Capital Market. The delisting decision will be reached under the NASDAQ Listing Rules 5101, 5110(b), and IM-5101-1 following our announcement that the Debtors filed the Chapter 11 Cases. Trading of our common units will be suspended by the NASDAQ, and a Form 25-NSE will be filed with the Securities and Exchange Commission, which will remove our securities from listing and registration on the NASDAQ Capital Market.

Following the expected delisting from the NASDAQ, our units will commence trading on the OTC Pink Marketplace under the symbol “EVEPQ”. We can provide no assurance that its units will commence or continue to trade on this market, whether broker-dealers will continue to provide public quotes of the units on this market, whether the trading volume of the units will be sufficient to provide for an efficient trading market or whether quotes for the units will continue on this market in the future.

Industry Conditions and Our Financial Position

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 2017, they continue to fluctuate.

Factors contributing to lower oil prices in recent years have included real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; excess global supply and buildup of oil inventory levels above the historical norm; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the US 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 are likely to continue to directionally follow the market for oil.

In 2017, oil, natural gas and natural gas liquids prices increased relative to previous years, but did not reach a level for our revenues and cash flows to sufficiently reduce our total leverage ratio to meet the longer term level required by our credit agreement, which 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.

In response, we took a number of actions in 2017 to preserve our liquidity and financial flexibility, including:

As a result of the steps above, at December 31, 2017, we had over $66 million of liquidity available between our borrowing base capacity and cash on hand. However, our current leverage position, covenant defaults under our credit facility and our Indenture governing our Senior Notes and the fact that we have less production hedged at lower prices in 2018 relative to previous years, has required us to take additional steps going forward into 2018 to continue to preserve our liquidity and financial flexibility. These steps include:

During 2016 and 2017, the board of directors of EV Management announced that it had elected to suspend distributions for those fiscal years. The Partnership continues to generate positive distributable cash flow, albeit at significantly lower levels than previous years. However, to reinstate distributions, we must be in compliance with the covenants contained in our current credit agreement. We do not anticipate that we will be able to reinstate distributions in the foreseeable future, given that our operating cash flows have not increased, and are currently unlikely to increase, to a level that can support a sustainable distribution in compliance with theses covenants.

Furthermore, as of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default. This has a material, adverse effect on our business, including our ability to resume and sustain distributions. See “Item 1A. Risk Factors - Covenants in our credit agreement may restrict our ability to resume and sustain distributions.”

Acquisition of Eagle Ford Shale Properties

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, Texas 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.

Our Relationship with EnerVest

Our general partner is and historically has been EV Energy GP. Its general partner is EV Management, which is a wholly owned subsidiary of EnerVest. Through our omnibus agreement with EnerVest, EnerVest agrees to make available to us 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 36,500 wells across 15 states, 8.0 million acres under lease and 4.4 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 93% of our proved oil and gas reserves as of December 31, 2017. The EnerVest partnerships own interests in oil and gas properties in which we own interests. The properties are primarily located in the Barnett Shale, the Appalachian Basin and the San Juan Basin, and these properties represent approximately 74% of our net proved reserves at December 31, 2017. 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.

On March 8, 2018, our Board of Directors, after receiving the recommendation of our conflicts committee, approved an extension of our Omnibus Agreement with EnerVest through the end of 2018, at a monthly fee of $1,433,333.

As a result of the Restructuring, we anticipate that EV Energy GP and EV Management will be dissolved. Pursuant to the Restructuring Support Agreement, EnerVest has agreed to continue to satisfy, consistent with past practice, all obligations to the Debtors under the existing omnibus agreement and any joint operating agreements and other operating agreements to which the Debtors and EnerVest are party and has agreed to negotiate in good faith the terms of a new omnibus agreement and any modifications to the joint operating agreements and other operating agreements to which the Debtors and EnerVest are party.

Oil and Natural Gas Producing Activities

At December 31, 2017, 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 Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin, the Monroe Field in Northern Louisiana and Karnes County, Texas.

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, 2017 were 291.1 Bcfe, 64% of which is natural gas. During 2017, we drilled 9 gross wells (2.5 net wells) in the Barnett Shale, which were successfully completed. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average 27% working interest in 1,398 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, 2017 were 165.3 Bcfe, 65% of which is natural gas. During 2017, we did not drill any wells in the San Juan Basin. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average 79% working interest in 502 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, 2017 were 144.3 Bcfe, 69% of which is natural gas. During 2017, we did not drill any wells in the Appalachian Basin. EnerVest operates wells representing 86% of our estimated net proved reserves in this area, and we own an average 63% working interest in 9,876 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, 2017 were 72.1 Bcfe, 97% of which is natural gas. During 2017, 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 61% working interest in 1,625 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, 2017 was 46.2 Bcfe, 49% of which is natural gas. During 2017, we drilled 2 gross wells (0.3 net wells) in Central Texas, which were successfully completed. In August 2017, we acquired a 40% working interest in additional oil and gas properties in central Texas for $2.7 million (net of post-closing purchase price adjustments) from a third party. EnerVest operates wells representing 98% of our estimated net proved reserves in this area, and we own an average 22% working interest in 1,544 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, 2017 were 33.5 Bcfe, 65% of which is natural gas. During 2017, we did not drill any wells in the Mid-Continent area. EnerVest operates wells representing 15% of our estimated net proved reserves in this area, and we own an average 16% working interest in 1,610 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, 2017 were 27.1 Bcfe, 36% of which is natural gas. During 2017, 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 95% working interest in 136 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, 2017 were 24.1 Bcfe, 100% of which is natural gas. During 2017, 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 98% working interest in 3,851 gross productive wells.

Karnes County, Texas

On January 31, 2017, we acquired an additional 5.8% working interest in certain oil and gas properties in Karnes County, Texas for $58.7 million (net of post-closing purchase price adjustments). Our estimated net proved reserves as of December 31, 2017 were 9.9 Bcfe, 22% of which is natural gas. During 2017, we drilled 22 gross wells (1.0 net wells) in Karnes County, which were successfully completed. EnerVest operates wells representing 94% of our estimated net proved reserves in this area, and we own an average 6% working interest in 127 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, 2017:

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. PUDs 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.” 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 or both volumetric 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. The standardized measure of discounted future net cash flows 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, 2017, we have no reportable estimated PUDs with respect to any of our properties due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the PUD reserves. We previously reported estimated PUDs in SEC filings, and, if in the future we can satisfy the reasonable certainty criteria for recording PUDs as prescribed under the SEC requirements, we will likely report estimated PUDs in future filings.

At December 31, 2017, we had no PUDs compared with 87.1 Bcfe of PUDs at December 31, 2016. The following table describes the changes in our PUDs during 2017:

The following describes the material changes to our PUDs during 2017:

Revisions of previous estimates. The annual review of our PUDs for 2017 resulted in a negative revision of 85.0 Bcfe. This change from prior estimates results from uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the PUDs within the SEC five-year development limitation on PUDs. Further, decreases in prices for oil, natural gas and natural gas liquids have delayed the development of certain PUDs.

Converted to proved developed reserves. In 2017, we developed approximately 2.8% of our PUD volume and 2.5% of our PUD locations booked as of December 31, 2016 through the drilling of 4 gross (0.7 net) development wells. Of these reserves and wells, 1.4 Bcfe and 2 gross (0.4 net) wells are located in the Barnett Shale and the remaining 0.7 Bcfe and 2 gross (0.3 net) wells produce from the Austin Chalk located in the Central Texas area. Costs incurred relating to the development of PUDs were approximately $3.6 million during 2017.

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 88% and 12%, 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, 2017. 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.

⁽¹⁾       In addition, we own small royalty interests in over 1,000 wells.

Our Developed and Undeveloped Acreage

The following table sets forth information relating to our leasehold acreage as of December 31, 2017:

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, Average Sales Price and Average Production Cost by Field

The following table sets forth our production, production prices and production costs for 2017, 2016 and 2015 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, 2017 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2017:

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 2017, 2016 and 2015, 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, 2017, we were participating in the drilling of 17 gross (1.9 net) development wells.

We did not drill any exploratory wells in 2017 or in 2016. We drilled three gross (1.7 net) exploratory wells in 2015, all 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, provided that 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 2017, Energy Transfer Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 15.5% and 11.0%, respectively, of our consolidated oil, natural gas and natural gas liquids revenues. 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. 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 2018 and 2019 although it is unclear whether the Trump Administration will implement this initiative. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental regulation may continue for the long term.

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 (“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 US 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, the 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 the 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 (“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 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 (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 the 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 US Army Corps of Engineers. The EPA has issued final rules outlining its position on the federal jurisdictional reach over waters of the United States. 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. Further, 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 (the “BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in late 2017, the BLM repealed this rule.

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 (“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 (“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 (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“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, the 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, the 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 (“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; this legislation was not passed. 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. The EPA attempted to suspend enforcement of its methane rule, but this action was challenged on appeal and ruled improper. The EPA is reported to be considering rulemaking to rescind or revise the rule. Simultaneously with the methane rules for new and modified sources, the 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.

On November 18, 2016, the BLM published a final rule, which became effective on January 17, 2017, that was intended to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and Indian leases. Unlike the somewhat overlapping EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection and repair and other requirements regarding methane emissions. Just as the EPA has proposed a temporary stay of some of its requirements contained in NSPS Subpart OOOOa, as the EPA reconsiders some of these requirements, the BLM issued a proposed rule on February 12, 2018, that concludes that the costs the rule would impose would exceed the benefits it is expected to generate and therefore reduces those unnecessary compliance burdens, including requirements to write waste minimization plans, meet methane capture targets and use equipment that meets certain technical standards. It is too recent an event to determine the impact these proposed regulatory changes may have on oil and gas producers.

In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of 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 US 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 (“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, 2017, 2016 and 2015. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2018 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 and results of operations.

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 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 direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers 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 which at some time in the future might be determined to be non–reciprocal under the Mineral Act.

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.

Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-discriminatory basis at cost-based rates or at market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to produce evidence of the greenhouse gas (“GHG”) emissions of the proposed pipeline’s customers. In August 2017, the US Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, which required FERC to revise its environmental impact statement for the proposed pipeline to take into account GHG carbon emissions from downstream power plants using natural gas transported by the new pipeline. It is too early to determine the impacts of this Court decision, but it could be significant.

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 “ICA”). 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. In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the US Department of Transportation (the “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 addition, the PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and that operators establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisions to gathering line regulations and liquids pipelines regulations are enacted by the PHMSA, we could incur significant expenses.

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.

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.

Exports of US Crude Oil Production and Natural Gas Production

The federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. The general perception in the industry is that ending the prohibition of exports of oil produced in the US will be positive for producers of US oil. In addition, the US Department of Energy (the “DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting US natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, the DOE authorizes the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction of which are regulated by FERC. In the third quarter of 2016, the first quantities of natural gas produced in the lower 48 states of the US were exported as LNG from the first of several LNG export facilities being developed and constructed in the US Gulf Coast region. While it is too recent an event to determine the impact this change may have on our operations or our sales of natural gas, the perception in the industry is that this will be a positive development for producers of US natural gas.

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 six full–time employees who spend a significant amount of their time on our operations. At December 31, 2017, EnerVest, the sole member of EV Management, had 1,179 full–time employees, including over 89 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

Our business and operations are subject to many risks. The risks described below, in addition to the risks described in “Item 1. Business” and “Item 7A. Quantitative and Qualitative Disclosures About Market Risk” of this annual report, may not be the only risks we face, as our business and operations may also be subject to risks that we do not yet know of, or that we currently believe are immaterial. You should carefully consider the following risk factors together with all of the other information included in this annual report, including the financial statements and related notes, when deciding to invest in us. You should be aware that the occurrence of any of the events described in this Risk Factors section and elsewhere in this annual report could have a material adverse effect on our business, financial position, results of operations and cash flows and the trading price of our securities could decline and you could lose all or part of your investment.

Risks Related to our Restructuring and our Indebtedness

On April 2, 2018, we filed voluntary petitions commencing the Chapter 11 Cases under the Bankruptcy Code. The Chapter 11 Cases and the Restructuring may have a material adverse impact on our business, financial condition, results of operations, and cash flows. In addition, the Chapter 11 Cases and the Restructuring may have a material adverse impact on the trading price and ultimately are expected to result in the cancelation and discharge of our securities, including our equity units. Our proposed Plan, if confirmed by the Bankruptcy Court and consummated, will govern distributions to and the recoveries of holders of our securities.

We have engaged financial and legal advisors to assist us in, among other things, analyzing various strategic alternatives to address our liquidity and capital structure, including strategic and refinancing alternatives to restructure our indebtedness in private transactions. These restructuring efforts led to the execution of the Restructuring Support Agreement on March 13, 2018. Consistent with the Restructuring Support Agreement, on April 2, 2018, we commenced the Chapter 11 Cases in the Bankruptcy Court.

Commencing the Chapter 11 Cases could have a material adverse effect on our business, financial condition, results of operations and liquidity. So long as the Chapter 11 Cases continue, our senior management may be required to spend a significant amount of time and effort dealing with the reorganization instead of focusing on our business operations. Bankruptcy Court protection also may make it more difficult to retain management and the key personnel necessary to the success and growth of our business. In addition, during the period of time we are involved in a bankruptcy proceeding, our customers and suppliers might lose confidence in our ability to reorganize our business successfully and may seek to establish alternative commercial relationships.

Additionally, all of our indebtedness is senior to the existing common units in our capital structure. As a result, if the Bankruptcy Court confirms the Plan, then our common units will be canceled, resulting in a limited recovery for unitholders, and would place unitholders at a significant risk of losing all of their investment in our units. More specifically, pursuant to the Plan, existing common units would be canceled and would receive 5% of the new common stock (subject to dilution) and five-year warrants for 8% of the new common stock (subject to dilution) in the new, reorganized company, on a pro rata basis, with an exercise price set at an equity value at which the holders of the Senior Notes would receive a recovery equal to par plus accrued and unpaid interest as of the Petition Date in respect of the Senior Notes (after taking into account value dilution on account of the three percent of the new common stock to be allocated to the participants in the management incentive plan on the Effective Date pursuant to a management incentive plan).

Other significant risks include the following:

Because of the risks and uncertainties associated with Chapter 11 Cases, we cannot predict or quantify the ultimate impact that events occurring during the Chapter 11 Cases may have on our business, cash flows, liquidity, financial condition and results of operations, nor can we predict the ultimate impact that events occurring during the Chapter 11 Cases may have on our corporate or capital structure.

Any Partnership de-levering transaction or change in the Partnership’s capital structure, including in connection with a plan of reorganization in the Chapter 11 Cases, may involve significant taxable cancellation-of-debt or other income, such that the Partnership’s unitholders may be required to pay taxes on their share of such income even if they do not receive any cash distributions from the Partnership.

Our unitholders, as the owners of the Partnership, are allocated the taxable income (or loss) of the Partnership for income tax purposes. Each unitholder is required to report its share of our taxable income on its federal and applicable state and local income tax returns. Accordingly, depending on their individual tax position, each unitholder may be required to pay income taxes on its share of our taxable income, even if the unitholder receives no cash distributions from the Partnership, which could happen.

The Restructuring pursuant to the Plan is intended to be structured in a manner that minimizes, to the extent possible, the negative tax impact of cancellation of debt income (“CODI”) to our unitholders. Nevertheless, such transaction and any or other transactions we may engage in to de-lever the Partnership and manage its liquidity could result in the allocation of substantial taxable income to our unitholders without a corresponding cash distribution and possibly without any cash distribution. CODI may or may not be generated. The generation of CODI will depend on whether the principal amount of the outstanding Senior Notes, plus accrued and unpaid interest, exceeds the fair value of the equity received by the noteholders upon emergence from bankruptcy. Because the valuation upon emergence from bankruptcy is something determined in the future, we are currently unable to determine whether, and by how much, if any, the principal amount, plus accrued and unpaid interest, of the outstanding Senior Notes will exceed such valuation. If CODI is generated, it would be allocated to the unitholders of record as of the opening of the first NYSE trading day of the month we emerge from bankruptcy (the “CODI Allocation Date”). No CODI should be allocated to a unitholder with respect to units which are sold prior to the CODI Allocation Date. In certain cases, CODI can be realized even when existing debt is modified with no reduction in such debt’s stated principal amount. We will not make a corresponding cash distribution with respect to such allocation of CODI. Therefore, any CODI will cause a unitholder to be allocated income with respect to our units with no corresponding distribution of cash to fund the payment of the resulting tax liability to such unitholder. Such CODI, like other items of our income, gain, loss, and deduction that are allocated to our unitholders, will be taken into account in the taxable income of the holders of our units as appropriate. CODI is not itself an additional tax due but is an amount that must be reported as ordinary income by the unitholder, potentially increasing such unitholder’s tax liabilities.

Our unitholders may not have sufficient tax attributes (including allocated past and current losses from our activities) available to offset such allocated CODI. Moreover, CODI that is allocated to our unitholders will be ordinary income, and, as a result, it may not be possible for our unitholders to offset such CODI by claiming capital losses with respect to their units, even if such units are cancelled for no consideration in connection with such a restructuring. Importantly, certain exclusions that are available with respect to CODI generally do not apply at the partnership level, and any solvent unitholder that is not in a Chapter 11 proceeding will be unable to rely on such exclusions.

Each unitholder’s tax situation is different. The ultimate effect to each unitholder will depend on the unitholder’s individual tax position with respect to its units. Additionally, certain of our unitholders may have more losses available than other of our unitholders, and such losses may be available to offset some or all of the CODI that could be generated in a strategic transaction involving our debt. Accordingly, unitholders are highly encouraged to consult, and depend on, their own tax advisors in making such evaluation.

Additionally, the Partnership expects to emerge from the Chapter 11 Cases as a corporation, including for US federal income tax purposes.

During the existence of an event of default and the Chapter 11 Cases, we have no borrowing capacity under our credit agreement. Unless we are able to successfully restructure our existing indebtedness we may not be able to continue as a going concern.

Over the periods presented in the accompanying financial statements, our growth has been funded through a combination of borrowings under our credit agreement, the sale of assets and cash flows from operating activities. We currently have limited access to additional capital. During the existence of an event of default, we have no availability under our credit agreement.

The accompanying Consolidated Financial Statements have been prepared on a going concern basis which contemplates continuity of operations, realization of assets and liquidation of liabilities in the ordinary course of business. As a result of losses incurred, there is no assurance that the carrying amounts of assets will be realized or that liabilities will be settled for the amounts recorded. Unless we are able to successfully restructure our existing indebtedness under the Chapter 11 Cases we may not be able to continue as a going concern. There can be no assurance that the Plan as outlined in the Restructuring Support Agreement (or any other plan of reorganization) will be confirmed by the Bankruptcy Court and consummated.

Delays in our Chapter 11 Cases may increase the risks of our being unable to reorganize our business and emerge from bankruptcy and increase our costs associated with the bankruptcy process.

Our Restructuring Support Agreement contemplates the confirmation of the Plan through an orderly prepackaged plan of reorganization, but there can be no assurance that we will be able to confirm and consummate the Plan. In addition to obtaining the required votes of stakeholders (which requirement we believe we satisfied before commencing the Chapter 11 Cases), the requirements for the Bankruptcy Court to confirm a plan of reorganization include, among other judicial findings, that:

We may not be able to confirm the Plan promptly, if at all. In such event, a prolonged Chapter 11 bankruptcy proceeding could adversely affect our relationships with customers, suppliers and employees, among other parties, which in turn could adversely affect our business, competitive position, financial condition, liquidity and results of operations and our ability to continue as a going concern. A weakening of our financial condition, liquidity and results of operations could adversely affect our ability to implement our proposed Plan (or any other plan of reorganization). If no plan is confirmed by the Bankruptcy Court, we may be forced to liquidate our assets.

In addition, the confirmation and effectiveness of the Plan is subject to certain conditions and requirements in addition to those described above that may not be satisfied.

We believe it is likely that our common units will substantially decrease in value in our Chapter 11 Cases.

We have a significant amount of indebtedness that is senior to our common units in our capital structure. We believe that the existing common units will substantially decrease in value during and after emergence from the Chapter 11 Cases. Accordingly, any trading in our common units during the pendency of our Chapter 11 Cases is highly speculative and poses substantial risks to purchasers of our common units.

Pursuant to the Plan, existing common units will be canceled and will receive 5% of the new common stock (subject to dilution) and five-year warrants for 8% of the new common stock (subject to dilution) in the new, reorganized company, on a pro rata basis, with an exercise price set at an equity value at which the holders of the Senior Notes would receive a recovery equal to par plus accrued and unpaid interest as of the Petition Date in respect of the Senior Notes (after taking into account value dilution on account of the three percent of the new common stock to be allocated to the participants in the management incentive plan on the Effective Date pursuant to a management incentive plan).

The Restructuring Support Agreement is subject to significant conditions and milestones that may be difficult for us to satisfy.

There are certain material conditions we must satisfy under the Restructuring Support Agreement, including the timely satisfaction of milestones in the Chapter 11 Cases, including for confirmation and consummation of the Plan. Our ability to timely complete such milestones is subject to risks and uncertainties, many of which are beyond our control.

We may not be able to obtain confirmation of the Plan.

There can be no assurance that the Plan as outlined in the Restructuring Support Agreement (or any other plan of reorganization) will be confirmed by the Bankruptcy Court. As a result, investors should exercise caution with respect to existing and future investments in our securities. The success of any reorganization will depend on approval by the Bankruptcy Court, and there can be no guarantee of success with respect to the Plan or any other plan of reorganization. For instance, we might receive objections from stakeholders to confirmation of the Plan or other relief we seek in the Chapter 11 Cases. We cannot predict the impact of any such objections. Any objection may cause us to devote significant resources in response which could materially and adversely affect our business, financial condition and results of operations.

If the Plan is not confirmed by the Bankruptcy Court, it is unclear whether we would be able to reorganize our business and what, if any, distributions holders of claims against us, including holders of our existing indebtedness, would ultimately receive with respect to their claims. The Plan provides for a recovery to our public unitholders. If the Plan is not confirmed, we believe that any other plan is likely to provide a reduced recovery (or no recovery at all) to our unitholders and will place them at significant risk of losing most or all of their investments in the Partnership. See Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data.”

There can be no assurance to whether we will successfully reorganize and emerge from the Chapter 11 Cases or, if we do successfully reorganize, as to when we would emerge from the Chapter 11 Cases. If we are unable to successfully reorganize, we may not be able to continue our operations.

If the Restructuring Support Agreement is terminated, our ability to confirm and consummate the Plan could be materially and adversely affected.

The Restructuring Support Agreement contains a number of termination events, upon the occurrence of which certain parties to the Restructuring Support Agreement may terminate the agreement. If the Restructuring Support Agreement is terminated, each of the parties thereto will be released from their obligations in accordance with the terms of the Restructuring Support Agreement. Such termination may result in the loss of support for the Plan by the parties to the Restructuring Support Agreement, which could adversely affect our ability to confirm and consummate the Plan. If the Plan is not consummated, there can be no assurance that any new Chapter 11 plan of reorganization would be as favorable to holders of claims and units as the current Plan.

Even if a Chapter 11 plan of reorganization is consummated, we may not be able to achieve our stated goals and there is substantial doubt regarding our ability to continue as a going concern.

Even if the Plan or any other Chapter 11 plan of reorganization is consummated, we may continue to face a number of risks, such as further deterioration in commodity prices or other changes in economic conditions, changes in our industry, changes in demand for our oil and gas and increasing expenses. Some of these risks become more acute when a case under the Bankruptcy Code continues for a protracted period without indication of how or when the case may be completed. As a result of these risks and others, we cannot guarantee that any Chapter 11 plan of reorganization will achieve our stated goals.

In addition, at the outset of the Chapter 11 Cases, the Bankruptcy Code gives the Debtors the exclusive right to propose a plan of reorganization and prohibits creditors, equity security holders and others from proposing a plan. Accordingly, we currently have the exclusive right to propose a plan of reorganization. If that right is terminated, however, or the exclusivity period expires, there could be a material adverse effect on our ability to achieve confirmation of a plan of reorganization in order to achieve our stated goals.

Furthermore, even if our debts are reduced or discharged through a plan of reorganization, we may need to raise additional funds through public or private debt or equity financing or other various means to fund our business after the completion of the Chapter 11 Cases. Our access to additional financing may be limited, if it is available at all. Therefore, adequate funds may not be available when needed or may not be available on favorable terms, if they are available at all.

As a result of the entry into the Chapter 11 Cases, even with the creditor support for the restructuring under the Restructuring Support Agreement, there is substantial doubt regarding our ability to continue as a going concern. As a result, we cannot give any assurance of our ability to continue as a going concern, even if a plan of reorganization is confirmed.

Our common units will be delisted from trading on the NASDAQ Capital Market, and no longer been listed on a national securities exchange effective following the commencement of the Chapter 11 Cases, and will be quoted only in the over-the-counter market, which could negatively affect the price and liquidity of our common units.

In connection with filing the Chapter 11 Cases, we expect to receive a notice from the NASDAQ stating that our units will be delisted from the NASDAQ Capital Market. The delisting decision will be reached under the NASDAQ Listing Rules 5101, 5110(b), and IM-5101-1 following our announcement that the Debtors filed the Chapter 11 Cases. Trading of our common units will be suspended by the NASDAQ, and a Form 25-NSE will be filed with the Securities and Exchange Commission, which will remove our securities from listing and registration on the NASDAQ Capital Market.

Following the expected delisting from the NASDAQ Capital Market, our units will commence trading on the OTC Pink Marketplace under the symbol “EVEPQ”. We can provide no assurance that its units will commence or continue to trade on this market, whether broker-dealers will continue to provide public quotes of the units on this market, whether the trading volume of the units will be sufficient to provide for an efficient trading market or whether quotes for the units will continue on this market in the future.

The OTC Pink is a significantly more limited market than the NASDAQ Capital Market, and the quotation of our common units on the OTC Pink Marketplace may result in a less liquid market available for existing and potential shareholders to trade our common units. This could further depress the trading price of our common units and could also have a long-term adverse effect on our ability to raise capital. There can be no assurance that any public market for our common units will exist in the future or that we will be able to relist our common units on a national securities exchange. In connection with the delisting of our common units, there may also be other negative implications, including the potential loss of confidence in us by suppliers, customers and employees and the loss of institutional investor interest in our common units

In certain instances, a Chapter 11 case may be converted to a case under Chapter 7 of the Bankruptcy Code.

Upon a showing of cause, the Bankruptcy Court may convert our Chapter 11 Cases to a case under Chapter 7 of the Bankruptcy Code. In such event, a Chapter 7 trustee would be appointed or elected to liquidate our assets for distribution in accordance with the priorities established by the Bankruptcy Code. We believe that liquidation under chapter 7 would result in significantly smaller distributions being made to our creditors than those provided for in our Plan because of (i) the likelihood that the assets would have to be sold or otherwise disposed of in a distressed fashion over a short period of time rather than in a controlled manner and as a going concern, (ii) additional administrative expenses involved in the appointment of a Chapter 7 trustee, and (iii) additional expenses and claims, some of which would be entitled to priority, that would be generated during the liquidation and from the rejection of leases and other executory contracts in connection with a cessation of operations.

As a result of the Chapter 11 Cases, our historical financial information may not be indicative of our future performance, which may be volatile.

During the Chapter 11 Cases, we expect our financial results to continue to be volatile as restructuring activities and expenses, contract terminations and rejections, and claims assessments significantly impact our consolidated financial statements. As a result, our historical financial performance is likely not indicative of our financial performance after the date of the filing of the Chapter 11 Cases. In addition, if we emerge from Chapter 11, the amounts reported in subsequent consolidated financial statements may materially change relative to historical consolidated financial statements, including as a result of revisions to our operating plans pursuant to the Plan. We also may be required to adopt fresh start accounting, in which case our assets and liabilities will be recorded at fair value as of the fresh start reporting date, which may differ materially from the recorded values of assets and liabilities on our consolidated balance sheets. Our financial results after the application of fresh start accounting also may be different from historical trends.

We may be subject to claims that will not be discharged in the Chapter 11 Cases, which could have a material adverse effect on our financial condition and results of operations.

The Bankruptcy Court provides that the confirmation of a plan of reorganization discharges a debtor from substantially all debts arising prior to confirmation. With few exceptions, all claims that arose prior to April 2, 2018, or before confirmation of the Plan (i) would be subject to compromise and/or treatment under the Plan and/or (ii) would be discharged in accordance with the Bankruptcy Code and the terms of the Plan. Any claims not ultimately discharged pursuant to the Plan could be asserted against the reorganized entities and may have an adverse effect on our financial condition and results of operations on a post-reorganization basis.

We have significant exposure to fluctuations in commodity prices since none of our estimated future production is covered by commodity derivative contracts and we may not be able to enter into commodity derivative contracts covering our estimated future production on favorable terms or at all.

During the Chapter 11 Cases, our ability to enter into commodity derivative contracts covering estimated future production will be limited. As a result, we may not be able to enter into commodity derivative contracts covering our production in future periods on favorable terms or at all. If we cannot or choose not to enter into commodity derivative contracts in the future, we could be more affected by changes in commodity prices. Our inability to hedge the risk of low commodity prices in the future, on favorable terms or at all, could have a material adverse impact on our business, financial condition and results of operations.

We may experience employee attrition as a result of the Chapter 11 Cases.

As a result of the Chapter 11 Cases, we may experience employee attrition, and our employees may face considerable distraction and uncertainty. A loss of key personnel or material erosion of employee morale could adversely affect our business and results of operations. Our ability to engage, motivate and retain key employees or take other measures intended to motivate and incentivize key employees to remain with us through the pendency of the Chapter 11 Cases is limited by restrictions on implementation of incentive programs under the Bankruptcy Code. The loss of services of members of our senior management team could impair our ability to execute our strategy and implement operational initiatives, which would be likely to have a material adverse effect on our financial condition, liquidity and results of operations.

Risks Related to Our Business

The board of directors of our general partner has suspended quarterly cash distributions on our common units and, in connection with the transactions contemplated by the Plan in the Chapter 11 Cases, we will convert into an entity that will not seek to pay a quarterly cash distribution or any other amount to equity holders.

Since 2016, we have suspended cash distributions to the holders of our common units in order to conserve cash and improve our liquidity. In connection with the transactions contemplated by the Plan in the Chapter 11 Cases, the Partnership will convert into a corporation or other entity with a primary business objective other than generating stable cash flows that will allow for quarterly cash distributions to equity holders.

If we were to resume quarterly cash distributions, the cash available to service our indebtedness or otherwise operate our business may be limited and we may be required to incur additional debt to enable us to pay such quarterly distributions.

If we were to resume quarterly cash distributions, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on our indebtedness or otherwise operate our business. For more information, see below “—- 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 credit 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. As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default. This has 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.

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 prior to the second half of 2014. 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. 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 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:

The terms of our indebtedness include restrictions and financial covenants that may restrict our business and financing activities.

The operating and financial restrictions and covenants in any future financing agreements may restrict our ability to finance future operations or capital needs or to engage, expand or pursue our business activities or to pay distributions to our unitholders. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of such financing agreements that are not cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

The terms and conditions governing our indebtedness:

We expect our Exit Credit Facility to be at least as restrictive as our revolving credit facility.

Our lenders periodically redetermine the amount we may borrow under our credit facility, which may materially impact our operations.

Our credit facility allowed, and we expect our Exit Credit Facility will allow, us to borrow in an amount up to the borrowing base, which is primarily based on the estimated value of our oil and natural gas properties and our commodity derivative contracts as determined semi-annually by our lenders in their sole discretion. The borrowing base is subject to redetermination on at least a semi-annual basis primarily based on an engineering report with respect to our estimated natural gas, oil and NGL reserves, which takes into account the prevailing natural gas, oil and NGL prices at such time, as adjusted for the impact of our commodity derivative contracts.  Accordingly, declining commodity prices may have an impact on the amount we can borrow, which could affect our cash flows and ability to execute on our business plans. Any reduction in the borrowing base would materially and adversely affect our business and financing activities, limit our flexibility and management’s discretion in operating our business, and increase the risk that we may default on our debt obligations.  In addition, as hedges expire, the borrowing base is subject to further reduction. Our credit facility required, and we expect our Exit Credit Facility will require, us to repay any deficiency over a certain period or pledge additional oil and gas properties to eliminate such deficiency, which we are required to do within 30 days of electing to do so. If our outstanding borrowings exceed the borrowing base and we are unable to repay the deficiency or pledge additional oil and gas properties to eliminate such deficiency, our failure to repay any of the installments due related to the borrowing base deficiency would constitute an event of default under the credit facility and as such, the lenders could declare all outstanding principal and interest to be due and payable, could freeze our accounts, or foreclose against the assets securing the obligations owed under the credit facility.

We may not be able to generate enough cash flow to meet our debt obligations and may be forced to take other actions to satisfy our debt obligations that may not be successful. 

We have historically funded our operations, including our operating and capital expenditures, our debt service obligations and our acquisitions primarily through cash generated from operations, amounts available under our credit facility and equity and debt offerings. Our future cash flows are subject to a number of variables, including oil and natural gas prices, and due to the steep decline in commodity prices, our ability to obtain funding in the equity or capital markets has been, and will continue to be, constrained, and there can be no assurances that our liquidity requirements will continue to be satisfied given current commodity prices.  If our sources of liquidity are not sufficient to fund our current or future liquidity needs, including as a result of a decrease in the borrowing base under our credit facility, we may be required to take other actions, including those actions discussed below.

We expect our earnings and cash flow to vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can service in some periods may not be appropriate for us in other periods. Moreover, and subject to certain limitations, we may be able to incur substantial additional indebtedness in the future. Additionally, our future cash flow may be insufficient to meet our debt obligations and commitments. Any insufficiency could negatively impact our business. A range of economic, competitive, business and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to pay our debt. Many of these factors, such as oil and natural gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake alternative strategic actions or financing plans, such as:

We continually monitor the capital markets and our capital structure and may make changes to our capital structure from time to time, with the goal of maintaining financial flexibility, preserving or improving liquidity, strengthening our balance sheet, meeting our debt service obligations and/or achieving cost efficiency.  Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of our indebtedness could cause us to incur high transaction costs, may be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict our business operations. The terms of existing or future debt instruments, including our credit facility, may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on our outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet our debt service and other obligations. Our debt instruments restrict our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due.

We can provide no assurances that any alternative strategic action or financing plan undertaken will be successful in allowing us to meet our debt obligations or will result in additional liquidity. Our inability to generate sufficient cash flow to satisfy our debt obligations or to obtain alternative financing could materially and adversely affect our ability to make payments on our indebtedness and our business, financial condition, results of operations and cash flows.

Despite our current level of indebtedness, we may still be able to incur substantially more debt. This could further exacerbate the risks associated with our substantial indebtedness.

We and our subsidiaries may be able to incur substantial additional indebtedness in the future, subject to certain limitations, including under our credit facility or our Exit Credit Facility. If new debt is added to our current debt levels, the related risks that we now face could increase. Our level of indebtedness could, for instance, prevent us from engaging in transactions that might otherwise be beneficial to us or from making desirable capital expenditures. This could put us at a competitive disadvantage relative to other less leveraged competitors that have more cash flow to devote to their operations. In addition, the incurrence of additional indebtedness could make it more difficult to satisfy our existing financial obligations.

Our variable rate indebtedness subjects us to interest rate risk, which could cause our debt service obligations to increase significantly.

Borrowings under our credit facility bear interest at variable rates and expose us to interest rate risk. If interest rates increase and we are unable to effectively hedge our interest rate risk, our debt service obligations on the variable rate indebtedness would increase even if the amount borrowed remained the same, and our net income and cash available for servicing our indebtedness would decrease. See “Item 7A. Quantitative and Qualitative Disclosures About Market Risk — Interest Price Risk” included under Part II of this annual report for further information regarding interest rate sensitivity.

The board of directors of our general partner has suspended quarterly cash distributions on common units and, in connection with the transactions contemplated by the plan of reorganization in the Chapter 11 Cases, we will convert into an entity that will not seek to pay a quarterly cash distribution or any other amount to equity holders.

Under the terms of our partnership agreement, we distribute all of our available cash to our unitholders after reserves established by our general partner. The amount of cash available for distribution is reduced by our operating expenses and the amount of any cash reserves established by our general partner to provide for future operations, future capital expenditures, including acquisitions of additional oil and natural gas properties, and future debt service requirements. In 2016, the board of directors of our general partner suspended and has not reinstated distributions on common units primarily due to the current and expected commodity price environment and market conditions and their impact on our future business as well as restrictions imposed by our debt instruments, including our credit facility.

In connection with the transactions contemplated by the plan of reorganization in the Chapter 11 Cases, the Partnership will convert into a corporation or other entity with a primary business objective other than generating stable cash flows that will allow for quarterly cash distributions to equity holders.

If we were to resume quarterly cash distributions, the cash available to service our indebtedness or otherwise operate our business may be limited and we may incur additional debt to enable us to pay such quarterly distributions.

If we were to resume quarterly cash distributions, we may not accumulate significant amounts of cash. These distributions could significantly reduce the cash available to us in subsequent periods to make payments on our indebtedness or otherwise operate our business.

In addition, we may be unable to pay the quarterly cash distribution, if resumed, without borrowing under our credit facility or otherwise. If we use borrowings to pay distributions to our equity holders for an extended period of time rather than to fund capital expenditures and other activities relating to our operations, we may be unable to maintain or grow our business. Such a curtailment of our business activities, combined with our payment of principal and interest on our future indebtedness incurred to pay these distributions, will reduce our cash available for distribution on our equity and will have a material adverse effect on our business, financial condition and results of operations.

Our inability to finance the development of our properties, future oil and natural gas price declines and other factors may result in additional write-downs 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 2017, we recorded impairment charges of approximately $93.6 million. The impairment charges during 2017 included $69.9 million of proved oil and natural gas properties, of which, $49.5 million related to properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to properties located in the Monroe Field, $2.2 million related to properties located in Central Texas and $2.9 million related to properties in East Texas which were sold during April 2017. 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, 2017, commodity prices have continued to fluctuate. If commodity prices significantly decrease in future quarters, we could have additional impairments of our oil and natural gas properties.

As of December 31, 2017, we had no estimated proved undeveloped reserves (“PUDs”).

As of December 31, 2017, we did not report any estimated PUDs with respect to any of our properties due to uncertainty regarding our ability to continue as a going concern and the availability of capital that would be required to develop the PUDs. These undeveloped properties may not be ultimately developed by us. We previously reported estimated PUDs in our SEC filings, and, if in the future we can satisfy the reasonable certainty criteria for recording PUDs as prescribed under the SEC requirements, we would likely report estimated PUDs in future filings.

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, 2017, we had over 3,374 gross identified potential drilling locations, of which approximately 1,360 were located in the Barnett Shale and approximately 1,100 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 noted above, we did not include any reserves attributable to our identified potential drilling as PUDs.

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 recovery of PUDs requires significant capital expenditures and successful drilling operations. We can provide no assurances that we will have the ability to finance these future expenditures, whether development will occur as scheduled or that the results of such development will be as estimated. In addition, delays in the development could force us to reclassify certain of our proved reserves as unproved reserves. Further, the decision of the operators to develop the PUDs 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 EnerVest partnerships in the future. These properties are primarily in the Barnett Shale and San Juan Basin, and these properties represent approximately 56% of our estimated net proved reserves as of December 31, 2017. 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 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 these 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 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, result in financial losses or could reduce our net income, which may adversely affect our ability to service our debt obligations and expose us to counterparty credit risk.

While we currently have no commodity price derivative hedges in place, we enter into derivative contracts from time to time to manage our exposure to fluctuations in oil, natural gas and natural gas liquids prices, to achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids. 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, 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.

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 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. In addition, as substantial doubt exists that we will be able to continue as a going concern, finding counterparties for commodity hedges has proven difficult.

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 except that the Exit Credit Facility will require the Partnership to hedge no less than 70% of forecasted proved developed producing production not later than the closing date and for the 18-month period thereafter. 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 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 liquidity and results of operations.

One of our 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 condition and results of operations and our ability to 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 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 and financial condition.

Our future acquisition and development operations will require substantial capital expenditures. 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.

We intend to finance our future capital expenditures with cash flows from operations, borrowings under our Exit Credit Facility, as amended and restated upon approval of the Plan in the Chapter 11 Cases 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 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 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 US 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 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 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.

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.

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 and results of operations.

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 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.

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 of methane from existing wells and other facilities 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. As noted elsewhere in this report, both the EPA and BLM have proposed regulatory changes that would reduce the burdens of the above-described GHG emission regulations on new and existing sources, but it is too recent an event to know for certain the impact of these proposed rule changes.

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.

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. Litigation surrounding this rule is ongoing. Further, the EPA has published guidance on hydraulic fracturing using diesel and also 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 ability to issue additional 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 US 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 which could adversely affect our ability to service our debt obligations.

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.

 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.

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.

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, communicate with our employees, vendors and service providers, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities and global competition for oil and gas resources make certain information the target of theft or misappropriation.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.

Our technologies, systems, networks, and those of our vendors and service providers may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

A cyber incident involving our information systems and related infrastructure, or that of our vendors and service providers, could disrupt our business plans and negatively impact our operations in the following ways, among others:

Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats 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 information security vulnerabilities.

Risks Inherent in an Investment in Us

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, 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. 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 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 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 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. 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:

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.

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.

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 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

An IRS contest of our US federal income tax positions may adversely affect the market for our common units, and the cost of any IRS contest may be substantial.

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.

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–US 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–US persons will be reduced by withholding taxes at the highest applicable effective tax rate, and non–US persons will be required to file US 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.

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 US 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 US federal income tax purposes. Any modification to the US 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 US 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 “Item 1. Business — 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, 2017.

Please see “Item 1. Business — Restructuring and Bankruptcy Proceedings under Chapter 11” contained herein.

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 Capital Market (the “NASDAQ”) under the symbol “EVEP.” At the close of business on March 27, 2018, based upon information received from our transfer agent and brokers and nominees, there were 49,368,869 common units outstanding and we had 290 common unitholders of record. This number does not include owners for whom common units are 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 2017 and 2016:

On July 17, 2017, we received a letter from the NASDAQ notifying us that we were not in compliance with the NASDAQ Global Market’s rules that require the minimum bid price of our units to be at least $1.00 per share over a consecutive 30-trading-day period. On December 27, 2017, we applied to transfer from the NASDAQ Global Market to the NASDAQ Capital Market and requested an additional 180-day grace period to regain compliance with the NASDAQ Capital Market’s minimum bid price requirement because our common units have continued to trade below the $1.00 minimum closing bid price. In January 2018, NASDAQ approved both the transfer and the extension of the 180-day grace period, which will end on July 16, 2018. This notice from NASDAQ does not affect our business operations or trigger any default or other violation of our debt or other material obligations.

In connection with filing the Chapter 11 Cases, we expect to receive a notice from the NASDAQ stating that our units will be delisted from the NASDAQ Capital Market. The delisting decision will be reached under NASDAQ Listing Rules 5101, 5110(b), and IM-5101-1 following our announcement that the Debtors filed the Chapter 11 Cases. Trading of our common units will be suspended by the NASDAQ, and a Form 25-NSE will be filed with the Securities and Exchange Commission, which will remove our securities from listing and registration on the NASDAQ Capital Market.

Following the expected delisting from the NASDAQ, our units will commence trading on the OTC Pink Marketplace under the symbol “EVEPQ”. We can provide no assurance that its units will commence or continue to trade on this market, whether broker-dealers will continue to provide public quotes of the units on this market, whether the trading volume of the units will be sufficient to provide for an efficient trading market or whether quotes for the units will continue on this market in the future.

Cash Distributions to Unitholders

Suspension of Cash Distribution

The board of directors of EV Management elected to suspend cash distributions to our unitholders in 2017 and 2016, in order to conserve cash and improve liquidity.

As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default. This has a material, adverse effect on our business, including our ability to resume and sustain distributions.

Distribution Mechanics

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 12 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 interests in Cardinal Gas Services, LLC (“Cardinal”) in October 2014 and in Utica East Ohio Midstream LLC (“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, 2017, 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 Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin, the Monroe Field in Northern Louisiana and Karnes County. As of December 31, 2017, we had estimated net proved reserves of 13.4 MMBbls of oil, 543.7 Bcf of natural gas and 31.6 MMBbls of natural gas liquids, or 813.6 Bcfe, and a standardized measure of $579.4 million.

Restructuring and Bankruptcy Proceedings under Chapter 11

Continued low oil and natural gas prices have had a significant adverse impact on our business, and, as a result of our financial condition, we were not able to continue as a going concern without restructuring our capital structure.

On March 13, 2018, the Debtors entered into the Restructuring Support Agreement with (i) the Supporting Noteholders of approximately 70% of the Senior Notes issued pursuant to the Indenture; (ii) the Supporting Lenders constituting approximately 94% of the principal amount outstanding under the credit facility; (iii) EnerVest; and (iv) EnerVest Operating.

The Plan, which remains subject to confirmation by the Bankruptcy Court and other closing conditions, provides that, among other things, on the effective date of the Plan (the “Effective Date”), subject to the occurrence and completion of certain structuring steps:

On March 14, 2018 the Debtors commenced the solicitation of votes from the holders of the Senior Notes to accept or reject the Plan in accordance with the terms of the Restructuring Support Agreement.

On April 2, 2018, the Debtors commenced the Chapter 11 Cases in the Bankruptcy Court. The Debtors have filed motions with the Bankruptcy Court seeking operational and procedural relief, including joint administration of their Chapter 11 Cases. The Debtors have also filed a motion requesting that the Bankruptcy Court schedule a hearing to confirm the Plan. If the Plan is confirmed by the Bankruptcy Court and becomes effective, then the claims of the lenders under the credit facility and the holders of the Senior Notes will be discharged. There can be no assurance regarding the Partnership’s ability to obtain confirmation of the Plan or approval of other relief in the Chapter 11 Cases, the Bankruptcy Court’s rulings in the Chapter 11 Cases or the ultimate outcome of the Chapter 11 Cases in general.

As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases described above accelerated the Partnership’s obligations under its credit facility and the Indenture governing the Senior Notes. Additionally, events of default, including cross-defaults, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, which is subject to a 30 day grace period. Under the Bankruptcy Code, the creditors under these debt agreements are stayed from taking any action against the Partnership as a result of an event of default.

For the duration of the Restructuring and after the Chapter 11 Cases, our operations and our ability to develop and execute our business plan are subject to risks and uncertainties associated with the Restructuring and Chapter 11 Cases. As a result of these risks and uncertainties, our assets, liabilities, officers and/or directors could be significantly different following the outcome of the Chapter 11 Cases, and the description of our operations, properties and capital plans included in these financial statements may not accurately reflect our operations, properties and capital plans following the Chapter 11 Cases.

The Partnership expects to continue its operations without interruption during the pendency of the Chapter 11 Cases. See Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information.

Ability to Continue as a Going Concern

As discussed above, as of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default.

Throughout 2017, our management, along with our legal and financial advisors, explored strategic alternatives to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. We specifically evaluated options with the lenders under our credit facility and the holders of our Senior Notes that would improve liquidity and deleverage the Partnership. Our ability to access the capital markets has been extremely limited. In addition, our credit facility is subject to scheduled redeterminations of its borrowing base, semi-annually as of April 1 and October 1. We do not have sufficient liquidity to repay amounts due under the credit agreement and the Senior Notes.

The significant risks and uncertainties related to our liquidity and the Chapter 11 Cases described above raise substantial doubt about our ability to continue as a going concern. The audited consolidated financial statements for the year ended December 31, 2017 have been prepared on a going concern basis of accounting, which contemplates continuity of operations, realization of assets, and satisfaction of liabilities and commitments in the normal course of business. The audited consolidated financial statements do not include any adjustments that might result from the outcome of the going concern uncertainty. If we cannot continue as a going concern, adjustments to the carrying values and classification of our assets and liabilities and the reported amounts of income and expenses could be required and could be material.

In order to decrease the Partnership’s level of indebtedness and maintain the Partnership’s liquidity at levels sufficient to meet its commitments, the Partnership has undertaken a number of actions, including minimizing capital expenditures and further reducing its recurring operating expenses. The Partnership believes that even after taking these actions, it will not have sufficient liquidity to satisfy its debt service obligations, meet other financial obligations and comply with its debt covenants. As a result, the Debtors filed petitions for reorganization under Chapter 11 of the Bankruptcy Code.

See Note 2 and 10 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” and “Item 1A. Risk Factors” for additional information regarding our debt instruments and bankruptcy proceedings under Chapter 11.

Operating 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 2017, they have continued to fluctuate.

Factors contributing to lower oil prices in recent years have included real or perceived geopolitical risks in oil producing regions of the world, particularly the Middle East; excess global supply and buildup of oil inventory levels above the historical norm; actions taken by the Organization of Petroleum Exporting Countries; and the strength of the US 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 are likely to continue to directionally follow the market for oil.

In 2017, oil, natural gas and natural gas liquids prices increased relative to previous years, but did not reach a level for our revenues and cash flows to sufficiently reduce our total leverage ratio to meet the longer term level required by our credit agreement. The continuation of these lower prices, coupled with our levels of leverage, has negatively affected our revenues, earnings and cash flows. Continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or additional 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, 2017 were $51.34 per Bbl of oil and $2.976 per MMBtu of natural gas, which is lower than current forward strip prices. Had we used the forward strip prices at December 31, 2017 through December 2030, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 6.0% higher and that our reserves on an Mcfe basis would have been approximately 2.6% higher than our reserves calculated using SEC prices.

Our Responses to the Operating Environment in 2017 and Our Operating Plan for 2018

In 2017 and through April 2, 2018, we took a number of actions to preserve our liquidity and financial flexibility, including:

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 completed the Eagle Ford Acquisition. Certain EnerVest institutional partnerships own an 87% working interest in, and EnerVest acts as operator of, the properties.

As a result of the steps above, as of December 31, 2017, we have over $66 million of liquidity between our borrowing base capacity and cash on hand. We expect to continue operations without interruption during the pendency of the Chapter 11 Cases. Going forward into 2018, we plan to take additional steps to continue to preserve our liquidity and financial flexibility. These steps include:

During 2017, the board of directors of EV Management announced that it had elected to suspend distributions to our common unitholders for each quarter during the fiscal year. A distribution will not be made to our unitholders with respect to the first quarter of 2018. While we continue to generate positive distributable cash flow, the levels of cash flow are significantly less than we generated in prior years, and not adequate presently to repay our outstanding indebtedness and make distributions to our unitholders.

As of April 2, 2018, the Partnership was in default under certain of its debt instruments. The Partnership’s filing of the Chapter 11 Cases accelerated the Partnership’s obligations under its credit facility and the Senior Notes. Additionally, events of default, including cross-defaults, are present, including the receipt of a going concern explanatory paragraph from the Partnership’s independent registered public accounting firm on the Partnership’s consolidated financial statements, subject to a 30 day grace period. As a result, our credit facility could become due and payable because of this event of default. This has a material, adverse effect on our business.

We typically enter into derivative instruments to reduce the impact of price volatility on our cash flows. As of December 31, 2017, we were a party to derivative contracts covering approximately 44% of our production attributable to our estimated net proved reserves through March 2018. Please refer to Item 7A. “Quantitative And Qualitative Disclosures About Market Risk” in this annual report for more information.

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.

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 2017, we spent $39.3 million of capital drilling and completing wells, a decline relative to our average capital expenditures for drilling and completion activities in previous years. As a result, we saw our total production decline throughout the year. For 2018, we plan to spend $55 - $65 million of capital in an effort to keep our production flat, or to achieve moderate growth. 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 US 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.

Sales proceeds are credited to the carrying value of the properties, and 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.

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.

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 have historically hedged 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.

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, 2017 Compared with the Year Ended December 31, 2016

Net loss for 2017 was $134.2 million compared with a net loss of $242.9 million for 2016. The significant factors in this change were (i) a $58.8 million favorable change in gain (loss) on derivatives; (ii) a $40.8 million increase in revenues; (iii) a $37.7 million decrease in impairment of oil and natural gas properties; and (iv) a $22.3 million decrease in depreciation, depletion and amortization. These factors were partially offset by a $47.7 million decrease in gain on early extinguishment of debt that occurred in 2016 when we redeemed $74.0 million of our outstanding Senior Notes.

Oil, natural gas and natural gas liquids revenues for 2017 totaled $223.3 million, an increase of $40.6 million compared with 2016. This was the result of increases of $58.7 million related to higher prices for oil, natural gas and natural gas liquids partially offset by a decrease of $18.1 million primarily related to decreased natural gas and natural gas liquids production.

Lease operating expenses for 2017 decreased $1.8 million compared with 2016 as the result of $13.6 million from decreased production offset by $11.8 million from a higher cost per Mcfe. The higher unit cost per Mcfe reflects lower production volumes. Lease operating expenses per Mcfe were $1.63 in 2017 compared with $1.46 in 2016.

Production taxes for 2017 increased $3.2 million compared with 2016 due to higher oil, natural gas and natural gas liquids revenues. Production taxes for 2017 were $0.17 per Mcfe compared with $0.10 per Mcfe for 2016.

Depreciation, depletion and amortization (“DD&A”) for 2017 decreased $22.3 million compared with 2016 due to $13.0 million of decreased production combined with $9.3 million from a lower average DD&A rate per Mcfe. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates, as well as impairment of oil and gas properties during the first half of 2017. DD&A for 2017 was $1.56 per Mcfe compared with $1.69 per Mcfe for 2016.

General and administrative expenses for 2017 totaled $32.3 million, a decrease of $1.3 million compared with 2016. This decrease is primarily the result of $2.3 million of lower equity compensation costs and $1.8 million of lower fees paid to EnerVest under our omnibus agreement; these were partially offset by $1.8 million of increased legal fees and $1.4 million of increased compensation costs. General and administrative expenses were $0.52 per Mcfe in 2017 compared with $0.48 per Mcfe in 2016.

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 $93.6 million and $131.3 million in 2017 and 2016, respectively. Of these amounts, $69.9 million and $89.5 million in 2017 and 2016, 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. Of the $69.9 million impairment charge for 2017, $49.5 million related to properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to properties located in the Monroe Field, $2.2 million related to properties in Central Texas and $2.9 million related to properties in East Texas which were sold during April 2017. The $89.5 million impairment charge for 2016 related to oil and natural gas properties in the Barnett Shale that were sold during December 2016. 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 2017 consisted of $23.7 million of leasehold impairments. 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.

In 2017, we recognized a gain of $1.0 million on the sale of certain non–core oil and natural gas properties.

Gain on derivatives, net was $22.9 million for 2017 compared with a loss on derivatives, net of $36.0 million for 2016. This change was attributable to changes in future oil and natural gas prices. The 12-month forward price at December 31, 2017 for oil averaged $59.40 per Bbl compared with $56.19 at December 31, 2016, and the 12-month forward prices at December 31, 2017 for natural gas averaged $2.86 per MmBtu compared with $3.61 at December 31, 2016. 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.

Interest expense for 2017 decreased $1.5 million compared with 2016 due to $2.0 million attributed to a lower weighted average long-term debt balance and $1.0 million attributed to a lower write-off of loan costs in 2017 due to the reduction in the borrowing base, partially offset by $1.5 million from a higher weighted average effective interest rate.

In 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our Senior Notes for $35.0 million.

In 2016, we recorded approximately $2.4 million of tax benefits as a result of tax refunds and lower taxes.

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.

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 6). 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 attributed to 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.

In 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our Senior Notes 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 Senior Notes 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 Utica East Ohio Midsteram LLC (“UEO”).

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 meeting our working capital needs.

In 2017, in response to continued lower prices, we took a number of actions, including 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, 2017, we have over $66 million of liquidity between our borrowing base capacity and cash on hand.

For 2018, we believe that cash on hand, proceeds from sales of assets, net cash flows generated from operations and borrowings under our expected Exit Credit Facility will be adequate to fund our capital budget and satisfy our short–term liquidity needs.

We may also utilize borrowings under our expected Exit 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, 2017, the credit facility had a capitalization of $1.0 billion and will expire in February 2020. Borrowings under the credit facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of December 31, 2017, the borrowing base was $325.0 million, and we had $263.0 million of indebtedness under the credit facility outstanding.

In October 2017, we entered into the tenth amendment (“Tenth Amendment”) to our credit agreement governing the credit facility. Specifically, the amendment:

The credit facility requires the maintenance of the following (as defined in the credit facility):

As of December 31, 2017, we had $343.3 million in aggregate principal amount outstanding of our Senior Notes. As of December 31, 2017, the aggregate carrying amount of the Senior Notes was $342.5 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.

If the Partnership effectuates the Restructuring pursuant to the Restructuring Support Agreement and the Plan, then the claims of the lenders under the credit facility and the holders of the Senior Notes will be cancelled. See Note 2 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” for additional information on the terms of the Restructuring Support Agreement.

Cash and Cash Equivalents

At December 31, 2017, we had $4.9 million of cash and cash equivalents, which included $0.6 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

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, 2017, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows