Harvest Oil & Gas Corp. - Quarter Report: 2017 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

Form 10-Q 

For the quarterly period ended June 30, 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 

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 whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definition of “accelerated filer,” “large accelerated filer” and “smaller reporting 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 o NO þ 

As of August 7, 2017, the registrant had 49,368,869 common units outstanding.

Table of Contents 

PART I. FINANCIAL INFORMATION

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

EV Energy Partners, L.P. 

Condensed Consolidated Balance Sheets 

(In thousands, except number of units) 

(Unaudited) 

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Operations 

(In thousands, except per unit data) 

(Unaudited) 

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Changes in Owners’ Equity 

(In thousands) 

(Unaudited) 

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P. 

Condensed Consolidated Statements of Cash Flows 

(In thousands) 

(Unaudited) 

See accompanying notes to unaudited condensed consolidated financial statements.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS 

Nature of Operations 

EV Energy Partners, L.P. together with its wholly owned subsidiaries (“we,” “our” or “us”) is a publicly held limited partnership. 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 also 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.

Basis of Presentation 

Our unaudited condensed consolidated financial statements included herein have been prepared pursuant to the rules and regulations of the Securities and Exchange Commission (the “SEC”). Accordingly, certain information and disclosures normally included in annual financial statements prepared in accordance with accounting principles generally accepted in the United States of America have been condensed or omitted. We believe that the presentations and disclosures herein are adequate to make the information not misleading. The unaudited condensed consolidated financial statements reflect all adjustments (consisting of normal recurring adjustments) necessary for a fair presentation of the interim periods. The results of operations for the interim periods are not necessarily indicative of the results of operations to be expected for the full year. These interim financial statements should be read in conjunction with our audited consolidated financial statements and the related notes included in our Annual Report on Form 10–K for the year ended December 31, 2016. 

All intercompany accounts and transactions have been eliminated in consolidation. In the Notes to Unaudited Condensed Consolidated Financial Statements, all dollar and unit amounts in tabulations are in thousands of dollars and units, respectively, unless otherwise indicated.

Liquidity

Our unaudited condensed consolidated financial statements for the three and six months ended June 30, 2017 have been prepared assuming that we will continue as a going concern. As discussed in Note 7, at the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not have sufficient liquidity to repay amounts due under the credit agreement and Senior Notes.

Management is pursuing options to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. Among the options are (i) working with our bank syndicate to amend our credit agreement, (ii) seeking additional sources of capital, (iii) divesting or acquiring assets (see Note 3), (iv) redeeming or retiring additional amounts of Senior Notes, and (v) reducing operating costs. However, there can be no assurance that these options can be implemented and, if implemented, will be successful. Absent the implementation of actions that bring us into compliance with the covenants of our credit agreement or a meaningful increase in commodity prices, this raises substantial doubt about our ability to continue as a going concern within one year from the date these unaudited condensed consolidated financial statements are issued. These financial statements do not include any adjustments that might result from the outcome of this uncertainty.

New Accounting Standards

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09, Revenue from Contracts with Customers (“ASU 2014-09”. This ASU, as amended, superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The provisions of ASU 2014–09 are applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We plan to implement ASU 2014-09 as of January 1, 2018 using the modified retrospective method with the cumulative effect, if any, of initial adoption to be recognized at the date of initial application. We are currently in the process of evaluating the impact of the new standard on our accounting policies, processes, system requirements and financial reporting. Based on the evaluation performed to date, we expect to identify similar performance obligations as compared with deliverables and separate units of account previously identified, and we do not expect any change related to the allocation of the transaction price and the timing of our revenue to have a material impact on our unaudited consolidated financial statements. We will continue to assess the impact of adopting this ASU.

In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation (“ASU 2016-09”). This ASU simplifies several aspects of the accounting for employee share–based payment transactions, including the accounting for income taxes, forfeitures and statutory withholding requirements, as well as classification in the statement of cash flows. We adopted ASU 2016–09 on January 1, 2017. The adoption of this ASU did not have a material impact on our unaudited condensed consolidated financial statements. See Note 2 for further information.

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The main objective of ASU 2017-01 is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments of this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments of this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (ii) remove the evaluation of whether a market participant could replace missing elements. For public entities, ASU 2017-01 is effective for financial statements issued for fiscal years beginning after December 15, 2017, including interim periods within those fiscal years.

No other new accounting pronouncements issued or effective during the six months ended June 30, 2017 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements other than those disclosed in our Annual Report on Form 10-K for the year ended December 31, 2016.

Subsequent Events

We evaluated subsequent events for appropriate accounting and disclosure through the date these unaudited condensed consolidated financial statements were issued.

NOTE 2. EQUITY–BASED COMPENSATION

We may grant various forms of equity–based awards to employees, consultants and directors of EV Management and its affiliates who perform services for us. These equity–based awards currently consist of phantom units. 

We estimated the fair value of the phantom units using the Black–Scholes option pricing model. These phantom units are subject to graded vesting over a four year period. Historically, compensation cost has been recognized for these phantom units on a straight–line basis over the service period, net of estimated forfeitures. As of January 1, 2017, we made an accounting policy election to account for forfeitures as they occur, and compensation cost is now recognized for these phantom units on a straight-line basis over the service period with no adjustment for estimated forfeitures. As a result of this election, we recognized a cumulative adjustment to beginning retained earnings of $1.0 million during the six months ended June 30, 2017. Because the phantom units are equity awards, this cumulative adjustment was fully offset within owners’ equity.

We recognized compensation cost related to these phantom units of $1.0 million and $1.4 million in the three months ended June 30, 2017 and 2016, respectively, and $2.2 million and $3.0 million in the six months ended June 30, 2017 and 2016, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

As of June 30, 2017, there was $6.5 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.1 years.

NOTE 3. ACQUISITIONS AND DIVESTITURES

On January 31, 2017, we acquired a 5.8% working interest in oil and gas properties in Karnes County, Texas for $58.7 million (net of post-closing purchase price adjustments) with $52.1 million of proceeds from the divestiture of our Barnett Shale natural gas properties in December 2016 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 a wholly owned subsidiary of EnerVest and its affiliates acts as operator of, the properties. The purchase price of $58.7 million was primarily allocated to proved oil and natural gas properties, and this acquisition has an immaterial impact to our financial statements. The purchase price allocations for this acquisition are preliminary.

In February 2017, we, along with certain institutional partnerships managed by EnerVest, entered into an Agreement of Sale and Purchase to sell certain oil and gas properties in Ohio and Pennsylvania to a third party. The transaction closed on April 10, 2017, and we received net proceeds of $1.1 million. We did not record a gain or loss on this sale.

In April 2017, we sold certain oil and gas properties in East Texas to a third party. The transaction closed on April 5, 2017, and we received net proceeds of $0.6 million. We did not record a gain or loss on this sale.

NOTE 4. RISK MANAGEMENT 

Our business activities expose us to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, our floating rate credit facility exposes us to risks associated with changes in interest rates. As such, future earnings are subject to fluctuation due to changes in the market prices of oil, natural gas and natural gas liquids and interest rates. We use derivatives to reduce our risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. Our policies do not permit the use of derivatives for speculative purposes. 

We have elected not to designate any of our derivatives as hedging instruments. Accordingly, changes in the fair value of our derivatives are recorded immediately to operations as “Gain (loss) on derivatives, net” in our unaudited condensed consolidated statements of operations. 

As of June 30, 2017, we had entered into commodity contracts with the following terms: 

 As of June 30, 2017, we had entered into interest rate swaps with the following terms: 

The following table sets forth the fair values and classification of our outstanding derivatives:

We have entered into master netting arrangements with our counterparties. The amounts above are presented on a net basis in our unaudited condensed consolidated balance sheets when such amounts are with the same counterparty. In addition, we have recorded accounts payable and receivable balances related to our settled derivatives that are subject to our master netting agreements. These amounts are not included in the above table; however, under our master netting agreements, we have the right to offset these positions against our forward exposure related to outstanding derivatives.

Should our credit facility become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable. We could also be required to post cash collateral related to these derivatives under certain circumstances. As of June 30, 2017 and December 31, 2016, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

NOTE 5. FAIR VALUE MEASUREMENTS 

The fair value hierarchy has three levels based on the reliability of the inputs used to determine fair value. Level 1 refers to fair values determined based on quoted prices in active markets for identical assets or liabilities. Level 2 refers to fair values determined based on quoted prices for similar assets and liabilities in active markets or inputs that are observable for the asset or liability, either directly or indirectly through market corroboration. Level 3 refers to fair values determined based on our own assumptions used to measure assets and liabilities at fair value.

Recurring Basis

The following table presents the fair value hierarchy for our assets and liabilities that are required to be measured at fair value on a recurring basis: 

Our derivatives consist of over–the–counter contracts which are not traded on a public exchange. As the fair value of these derivatives is based on inputs using market prices obtained from independent brokers or determined using quantitative models that use as their basis readily observable market parameters that are actively quoted and can be validated through external sources, including third party pricing services, brokers and market transactions, we have categorized these derivatives as Level 2. We value these derivatives using the income approach with inputs such as the forward curve for commodity prices based on quoted market prices and prospective volatility factors related to changes in the forward curves and yield curves based on money market rates and interest rate swap data, such as forward LIBOR curves. Our estimates of fair value have been determined at discrete points in time based on relevant market data. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts to reflect counterparty credit quality and/or the effect of our own creditworthiness. Theses assumed credit risk adjustments are based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation techniques or related inputs in the six months ended June 30, 2017. 

Nonrecurring Basis

During the three months ended June 30, 2017, we recognized $18.2 million of impairment expense related to proved oil and natural gas properties; $15.3 million of this impairment related to properties located in the Monroe Field, and $2.9 million related to properties in East Texas which were sold during April 2017. During the six months ended June 30, 2017, we recognized $67.7 million of impairment expense related to proved oil and natural gas properties; $49.5 million of this impairment related to properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to properties located in the Monroe Field, and $2.9 million related to properties in East Texas which were sold during April 2017. During the three and six months ended June 30, 2016, we did not incur any impairment charges for any of our proved oil and natural gas properties.

The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from reserves. Significant Level 3 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.

Financial Instruments 

The estimated fair values of our financial instruments have been determined at discrete points in time based on relevant market information. Our financial instruments consist of cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities, derivatives and long–term debt. The carrying amounts of our financial instruments other than long–term debt approximate fair value because of the short–term nature of the items. Derivatives are recorded at fair value (see above). 

The carrying value of debt outstanding under our credit facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to us. The estimated fair value of our senior notes due April 2019 was $186.7 million and $242.6 million at June 30, 2017 and December 31, 2016, respectively, which differs from the carrying value of $342.2 million and $341.9 million at June 30, 2017 and December 31, 2016, respectively. The fair value of the senior notes due April 2019 was determined using Level 2 inputs.

NOTE 6. ASSET RETIREMENT OBLIGATIONS 

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. The changes in the aggregate ARO are as follows: 

As of June 30, 2017 and December 31, 2016, $2.4 million and $3.2 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 7. LONG–TERM DEBT 

Long–term debt, net consisted of the following:

Credit Facility 

As of June 30, 2017, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility are secured by a first priority lien on substantially all of our oil and natural gas properties. We may use borrowings under the facility for acquiring and developing oil and natural gas properties, for working capital purposes, for general corporate purposes and for funding distributions to partners. We also may use up to $100.0 million of available borrowing capacity for letters of credit. As of June 30, 2017, we have a $0.3 million letter of credit outstanding.

The facility does not require any repayments of amounts outstanding until it expires in February 2020. Borrowings under the facility bear interest at a floating rate based on, at our election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that we have outstanding (weighted average effective interest rate of 4.22% and 3.75% at June 30, 2017 and December 31, 2016, respectively). 

Borrowings under the facility may not exceed a “borrowing base” determined by the lenders under the facility based on our oil and natural gas reserves. In April 2017, the borrowing base under the facility was decreased $75.0 million to $375.0 million. As of June 30, 2017, the borrowing base under the facility was $375.0 million. The borrowing base is subject to scheduled redeterminations as of April 1 and October 1 of each year with an additional redetermination once per calendar year at our request or at the request of the lenders and with one calculation that may be made at our request during each calendar year in connection with material acquisitions or divestitures of properties.

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

As of June 30, 2017, we were in compliance with these financial covenants. Should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our short–term liquidity. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes.

8.0% Senior Notes due April 2019 

Our senior notes due April 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing wholly owned subsidiaries other than EV Energy Finance Corp. (“Finance”), which is a co–issuer of the Notes. Neither EV Energy Partners, L.P. nor Finance have independent assets or operations apart from the assets and operations of our subsidiaries.

NOTE 8. COMMITMENTS AND CONTINGENCIES

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 unaudited condensed consolidated financial statements and no amounts have been accrued at June 30, 2017 or December 31, 2016.

NOTE 9. OWNERS’ EQUITY 

Units Outstanding 

At June 30, 2017, owners’ equity consists of 49,368,869 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. 

Issuance of Units 

In the six months ended June 30, 2017, we issued 0.3 million common units related to the vesting of equity–based awards.

Cash Distributions 

During 2016, the board of directors of EV Management announced that it had elected to suspend distributions to unitholders for all four quarters of 2016. The board of directors also elected to suspend distributions for the first and second quarters of 2017.

NOTE 10. EARNINGS PER LIMITED PARTNER UNIT 

The following sets forth the calculation of earnings per limited partner unit:

NOTE 11. RELATED PARTY TRANSACTIONS 

Pursuant to an omnibus agreement, we paid EnerVest $3.5 million and $4.0 million in the three months ended June 30, 2017 and 2016, respectively, and $7.0 million and $8.0 million in the six months ended June 30, 2017 and 2016, respectively, in monthly administrative fees for providing us general and administrative services. These fees are based on an allocation of charges between EnerVest and us based on the estimated use of such services by each party, and we believe that the allocation method employed by EnerVest is reasonable and reflective of the estimated level of costs we would have incurred on a standalone basis. These fees are included in general and administrative expenses in our unaudited condensed consolidated statements of operations.

We have entered into operating agreements whereby a wholly owned subsidiary of EnerVest and its affiliates acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest. We reimbursed EnerVest approximately $4.9 million and $4.6 million in the three months ended June 30, 2017 and 2016, respectively, and $9.4 million and $10.8 million in the six months ended June 30, 2017 and 2016, respectively, for direct expenses incurred in the operation of our wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on our properties. As the vast majority of such expenses are charged to us on an actual basis (i.e., no mark-up or subsidy is charged or received by EnerVest), we believe that the aforementioned services were provided to us at fair and reasonable rates relative to the prevailing market and are representative of the costs that would have been incurred on a standalone basis. These costs are included in lease operating expenses in our unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collects proceeds from oil and natural gas sales and distributes them to us and other working interest owners.

As of June 30, 2017, EnerVest Operating owed us $7.2 million and partnerships managed by EnerVest owed us nothing. As of December 31, 2016, we owed EnerVest Operating $5.8 million and partnerships managed by EnerVest owed us $0.7 million.

NOTE 12. OTHER SUPPLEMENTAL INFORMATION

Supplemental cash flows and noncash transactions were as follows: 

Accounts payable and accrued liabilities consisted of the following:

ITEM 2. 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 our unaudited condensed consolidated financial statements and the related notes thereto, as well as our Annual Report on Form 10–K for the year ended December 31, 2016. 

OVERVIEW

We are a Delaware limited partnership formed in April 2006 by EnerVest to acquire, produce and develop oil and natural gas properties. 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. 

We operate in one reportable segment engaged in the acquisition, development and production of oil and natural gas properties and all of our operations are located in the United States.

As of June 30, 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), South Texas, the Monroe Field in Northern Louisiana, the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana and the Permian Basin. As of December 31, 2016, we had estimated net proved reserves of 12.6 MMBbls of oil, 575.3 Bcf of natural gas and 33.4 MMBbls of natural gas liquids, or 851.2 Bcfe, and a standardized measure of $371.1 million.

Current Price Environment

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

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

In the six months ended June 30, 2017, these low prices negatively affected our revenues, earnings and cash flows, and continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. Continued volatility or further declines in prices could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.

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

Our Response to the Current Price Environment

Given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include:

During 2016, the board of directors of EV Management elected to suspend distributions to unitholders for all four quarters of 2016. The board of directors also elected to suspend distributions for the first and second quarters of 2017. The company continues to generate positive distributable cash flow, albeit at significantly lower levels than in previous years. The board of directors will continue to evaluate on a quarterly basis and may elect to reinstate the distribution at the appropriate time when commodity prices and operating cash flows have increased to a level that can support a sustainable distribution.

As of August 7, 2017, we have $254.0 million outstanding under our credit facility and $343.3 million of our senior notes due 2019 outstanding, for a total of $597.3 million, and we have over $120 million of liquidity between our borrowing base capacity and cash on hand. Please see Note 1 to our unaudited condensed consolidated financial statements included in “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information regarding our liquidity.

Business Environment

One of our primary business objectives is to generate sufficient excess cash flow that will allow us to reinstate a stable distribution, which we will grow over time. The amount of cash we can distribute on our units principally depends upon the amount of cash generated from our operations, which will fluctuate from quarter to quarter based on, among other things:

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

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

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

RESULTS OF OPERATIONS 

Three Months Ended June 30, 2017 Compared with the Three Months Ended June 30, 2016

Net loss for the three months ended June 30, 2017 was $25.2 million compared with $29.0 million for the three months ended June 30, 2016. The significant factors in this change were a $42.1 million favorable change in gain on derivatives, a $13.2 million increase in total revenues, a $10.1 million decrease in depreciation, depletion and amortization, partially offset by a $47.7 million decrease as a result of the gain on extinguishment of debt during 2016 and a $16.4 million increase in impairment of oil and natural gas properties.

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2017 totaled $55.4 million, an increase of $13.0 million compared with the three months ended June 30, 2016. This was the result of an increase of $19.2 million related to higher prices offset by a decrease of $6.2 million primarily related to decreased natural gas and natural gas liquids production. 

Lease operating expenses for the three months ended June 30, 2017 increased $0.2 million compared with the three months ended June 30, 2016 as the result of $4.7 million from a higher unit cost per Mcfe, partially offset by $4.5 million from decreased production. Lease operating expenses were $1.68 per Mcfe in the three months ended June 30, 2017 compared with $1.42 per Mcfe in the three months ended June 30, 2016. 

Depreciation, depletion and amortization (“DD&A”) for the three months ended June 30, 2017 decreased $10.1 million compared with the three months ended June 30, 2016 as a result of $6.4 million from a lower unit cost per Mcfe combined with $3.7 million decreased production. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and impairments. DD&A was $1.38 per Mcfe in the three months ended June 30, 2017 compared with $1.73 per Mcfe in the three months ended June 30, 2016. 

General and administrative expenses for the three months ended June 30, 2017 totaled $7.0 million, a decrease of $0.9 million compared with the three months ended June 30, 2016. This decrease is primarily the result of $0.4 million of lower compensation costs and $0.5 million of lower fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.45 per Mcfe in the three months ended June 30, 2017 compared with $0.43 per Mcfe in the three months ended June 30, 2016. 

In the three months ended June 30, 2017, we incurred proved property impairment of $15.3 million related to proved oil and natural gas properties located in the Monroe Field and $2.9 million related to proved oil and natural gas properties located in East Texas which were sold during April 2017. During the three month ended June 30, 2017, we also incurred leasehold impairment charges of $0.2 million. In the three months ended June 30, 2016, we incurred leasehold impairment charges of $2.0 million.

Gain on derivatives, net was $6.5 million for the three months ended June 30, 2017 compared with a loss of $35.6 million for the three months ended June 30, 2016. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June 30, 2017 for oil averaged $47.19 per Bbl compared with $51.72 at March 31, 2017, and the 12 month forward prices at June 30, 2017 for natural gas averaged $3.09 per MmBtu compared with $3.37 at March 31, 2017. The 12 month forward price at June 30, 2016 for oil averaged $49.42 per Bbl compared with $38.56 at March 31, 2016, and the 12 month forward prices at June 30, 2016 for natural gas averaged $3.02 per MmBtu compared with $2.19 at March 31, 2016.

Interest expense for the three months ended June 30, 2017 decreased $1.4 million compared with the three months ended June 30, 2016 due to $1.2 million from less loan cost write off than the prior year combined with $0.4 million from a lower weighted average long–term debt balance and, partially offset by $0.2 million from a higher weighted average effective interest rate.

Six Months Ended June 30, 2017 Compared with the Six Months Ended June 30, 2016

Net loss for the six months ended June 30, 2017 was $76.0 million compared with $58.0 million for the six months ended June 30, 2016. The significant factors in this change were a $47.7 million decrease as a result of the gain on extinguishment of debt during 2016 and a $65.3 million increase in impairment of oil and natural gas properties, partially offset by a $46.5 million favorable change in gain on derivatives, a $32.0 million increase in total revenues, and a $11.3 million decrease in depreciation, depletion and amortization.

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2017 totaled $111.7 million, an increase of $31.6 million compared with the six months ended June 30, 2016. This was the result of an increase of $45.8 million related to higher prices offset by a decrease of $14.2 million primarily related to decreased natural gas and natural gas liquids production. 

Lease operating expenses for the six months ended June 30, 2017 decreased $4.8 million compared with the six months ended June 30, 2016 as the result of $9.0 million from decreased production, partially offset by $4.2 million from a higher unit cost per Mcfe. Lease operating expenses were $1.61 per Mcfe in the six months ended June 30, 2017 compared with $1.50 per Mcfe in the six months ended June 30, 2016. 

Depreciation, depletion and amortization (“DD&A”) for the six months ended June 30, 2017 decreased $11.3 million compared with the six months ended June 30, 2016 as a result of $8.7 million from decreased production combined with $2.6 million from a lower unit cost per Mcfe. The lower average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates and impairments. DD&A was $1.56 per Mcfe in the six months ended June 30, 2017 compared with $1.63 per Mcfe in the six months ended June 30, 2016. 

General and administrative expenses for the six months ended June 30, 2017 totaled $13.7 million, a decrease of $2.6 million compared with the six months ended June 30, 2016. This decrease is primarily the result of $1.1 million of lower compensation costs and $1.0 million of lower fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.44 per Mcfe in the six months ended June 30, 2017 compared with $0.45 per Mcfe in the six months ended June 30, 2016. 

In the six months ended June 30, 2017, we incurred proved property impairment of $49.5 million related to proved oil and natural gas properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to proved oil and natural gas properties located in the Monroe Field, and $2.9 million related to proved oil and natural gas properties located in East Texas which were sold in April 2017. During the six months ended June 30, 2017, we also incurred leasehold impairment charges of $0.3 million. In the six months ended June 30, 2016, we incurred leasehold impairment charges of $2.7 million.

Gain on derivatives, net was $20.7 million for the six months ended June 30, 2017 compared with a loss of $25.8 million for the six months ended June 30, 2016. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at June 30, 2017 for oil averaged $47.19 per Bbl compared with $56.19 at December 31, 2016, and the 12 month forward prices at June 30, 2017 for natural gas averaged $3.09 per MmBtu compared with $3.61 at December 31, 2016. The 12 month forward price at June 30, 2016 for oil averaged $49.42 per Bbl compared with $40.45 at December 31, 2015, and the 12 month forward prices at June 30, 2016 for natural gas averaged $3.02 per MmBtu compared with $2.49 at December 31, 2015.

Interest expense for the six months ended June 30, 2017 decreased $2.3 million compared with the six months ended June 30, 2016 due to $1.4 million from a lower weighted average long–term debt balance combined with $1.2 million from less loan cost write off than the prior year partially offset by $0.3 million from a higher weighted average effective interest rate.

LIQUIDITY AND CAPITAL RESOURCES

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

In response to continued price volatility, we have taken a number of actions to preserve our liquidity and financial flexibility and, as of August 7, 2017, we have over $120 million of liquidity between our borrowing base capacity and cash on hand. However, given current forward oil and natural gas prices and the fact that we have less production hedged at lower prices beginning in 2017 relative to previous years, we have taken additional steps going forward into 2017 to continue to preserve our liquidity and financial flexibility. These steps include those outlined in “—Overview—Our Response to the Current Price Environment.”

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

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

Long–term Debt

As of June 30, 2017, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of June 30, 2017, the borrowing base was $375.0 million, and we had $261.0 million outstanding.

In April 2017, the borrowing base was decreased to $375.0 million. Although the borrowing base under the credit facility was reduced, we believe we will maintain sufficient liquidity. However, should prices decline significantly from current levels, the borrowing base could be reduced again in future redeterminations, which would impact our liquidity. At the end of first quarter of 2018, the leverage covenant in our credit agreement changes from a senior secured debt to EBITDAX ratio to a total debt to EBITDAX ratio. Based on current forward commodity prices, at the end of first quarter of 2018, we project that we would likely have a total debt to EBITDAX ratio in excess of the level prescribed in the most recent Ninth Amendment of our credit agreement, and therefore we would not be in compliance with our leverage covenant at the end of the first quarter of 2018. Noncompliance with this covenant would be an event of default and could result in the acceleration of all our indebtedness under the credit agreement. If the lenders under the credit agreement were to accelerate the loans outstanding thereunder, we would also be in default under the indenture governing the Senior Notes, in which case the lenders under the indenture could accelerate repayment of the Senior Notes, and we would not have sufficient liquidity to repay amounts due under the credit agreement and Senior Notes.

As of June 30, 2017, we have $343.3 million in aggregate principal amount outstanding of our 8.0% senior notes due April 2019. As of June 30, 2017, the aggregate carrying amount of the senior notes due 2019 was $342.2 million.

As of August 7, 2017, we have $254.0 million outstanding under our credit facility and $343.3 million of our senior notes due April 2019 outstanding, for a total of $597.3 million.

For additional information about our long–term debt, such as interest rates and covenants, please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein.

Cash and Short–term Investments

At June 30, 2017, we had $3.6 million of cash and short–term investments, which included $0.7 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

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 June 30, 2017, all of our counterparties have performed pursuant to their derivative contracts.

Cash Flows

Cash flows provided by (used in) type of activity were as follows:

Operating Activities

Cash flows from operating activities provided $10.2 million and $14.4 million in the six months ended June 30, 2017 and 2016, respectively. The significant factors in the change were $13.4 million change in working capital, primarily related to higher accounts receivable as a result of higher sales prices during 2017 and $39.4 million of decreased cash settlements from our matured derivative contracts, partially offset by $32.0 million of higher revenues during 2017 and an $11.7 million federal tax payment related to the conversion of an acquired corporation to a single member LLC in 2016.

Investing Activities

During the six months ended June 30, 2017, we spent $58.7 million for acquisitions of oil and natural gas properties, utilized $52.1 million of restricted cash for those acquisitions, spent $3.6 million for additions to our oil and natural gas properties and received $2.0 million in proceeds from the sale of oil and natural gas properties. During the six months ended June 30, 2016, we spent $13.0 million for additions to our oil and natural gas properties and received $2.5 million in cash settlements from acquired derivative contracts and $2.4 million in proceeds from the sale of oil and natural gas properties.

Financing Activities

During the six months ended June 30, 2017, we received $17.0 million from borrowings under our credit facility and repaid $21.0 million of long–term debt borrowings.

During the six months ended June 30, 2016, we received $48.0 million from borrowings under our credit facility, repaid $33.0 million of long-term debt borrowings and paid distributions of $3.9 million to holders of our common units, phantom units and our general partner. We also redeemed $82.7 million of our senior notes due 2019 for $35.0 million.

FORWARD–LOOKING STATEMENTS

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

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

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

All of our forward–looking information is subject to risks and uncertainties that could cause actual results to differ materially from the results expected. Although it is not possible to identify all factors, these risks and uncertainties include the risk factors and the timing of any of those risk factors identified in the “Risk Factors” section included in Item 1A of our Annual Report on Form 10–K for the year ended December 31, 2016 and in “Item 1A. Risk Factors” contained herein.

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

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

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

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

Commodity Price Risk

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

We have entered into commodity contracts to hedge a portion of our anticipated oil and natural gas production through March 2018. As of June 30, 2017, we have commodity contracts covering approximately 77% of our estimated production attributable to our net proved reserves from July 2017 through March 2018, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our commodity contracts at June 30, 2017 was a net asset of $1.3 million. A 10% change in oil and natural gas prices with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such instruments) of our oil and natural gas commodity contracts of approximately $8.1 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

Interest Rate Risk

Our floating rate credit facility and interest rate swaps also expose us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in these interest rates. If interest rates on our facility increased by 1%, interest expense for the three and six months ended June 30, 2017 would have increased by approximately $0.7 million and $1.4 million, respectively. The fair value of our interest rate swaps at June 30, 2017 was a liability of approximately $59 thousand. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $12 thousand. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

ITEM 4. CONTROLS AND PROCEDURES

Evaluation of Disclosure Controls and Procedures

In accordance with Exchange Act Rule 13a–15 and 15d–15, we carried out an evaluation, under the supervision and with the participation of management, including our Chief Executive Officer and our Chief Financial Officer, of the effectiveness of our disclosure controls and procedures as of the end of the period covered by this report. Based on that evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2017 to provide reasonable assurance that information required to be disclosed in our reports filed or submitted under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Our disclosure controls and procedures include controls and procedures designed to ensure that information required to be disclosed in reports filed or submitted under the Exchange Act is accumulated and communicated to our management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Change in Internal Controls Over Financial Reporting

There have not been any changes in our internal controls over financial reporting that occurred during the quarterly period ended June 30, 2017 that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.

PART II. OTHER INFORMATION

ITEM 1. 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 adverse effect on our unaudited condensed consolidated financial statements.

ITEM 1A. RISK FACTORS

Other than the risk factor listed below, there have been no material changes with respect to the risk factors disclosed in our Annual Report on Form 10–K for the year ended December 31, 2016.

Uncertainty about future commodity prices and our ability to implement the actions described below that will allow us to remain in compliance with all of the restrictive covenants contained in our credit agreement raises substantial doubt about our ability to continue as a going concern.

Based on current forward commodity prices, we anticipate that we will be out of compliance with some of the financial covenants and ratios under our credit agreement by the end of the first quarter of 2018, which would cause us to be in default under the credit agreement. If we are unable to obtain a waiver or other suitable relief from the lenders, an Event of Default (as defined in the credit agreement) would result and the lenders could accelerate the outstanding indebtedness, making it immediately due and payable. If the indebtedness under the credit agreement is accelerated, then an Event of Default (as defined by the indenture governing the Senior Notes) under the Company's Senior Notes would occur, which, if it continues beyond any applicable cure periods, would result in the entire principal under the Senior Notes being due and payable immediately. If lenders, and subsequently noteholders, accelerate our outstanding indebtedness (approximately $603 million as of June 30, 2017), such indebtedness will become immediately due and payable, and we will not have sufficient liquidity to repay those amounts. In addition, should our credit facility agreement become due and payable because of an event of default, our derivatives that are in a net liability position could also become due and payable.

We are pursuing options to maintain sufficient liquidity and to address the credit agreement covenant compliance issue. Among the options are (i) working with our bank syndicate to amend our credit agreement, (ii) seeking additional sources of capital, (iii) divesting or acquiring assets, (iv) redeeming or retiring additional amounts of Senior Notes, and (v) reducing operating costs. However, there can be no assurance that these options can be implemented and, if implemented, will be successful. Absent the implementation of actions that bring us into compliance with the covenants of our credit agreement or a meaningful increase in commodity prices, this raises substantial doubt about our ability to continue as a going concern within one year from the date our unaudited condensed consolidated financial statements for the quarter ended June 30, 2017, which do not include any adjustments that might result from the outcome of this uncertainty, are issued. See Note 1 – Organization and Nature of Business to our unaudited condensed consolidated financial statements included in Part I, Item 1of this report.

We may engage in changes to our capital structure, such as transactions to reduce our indebtedness, that will generate taxable income (including cancellation of indebtedness income) allocable to unitholders, and income tax liabilities arising therefrom may exceed the value of a unitholder’s investment in us.

We continually monitor the respective 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 the balance sheet, meeting debt service obligations and/or achieving cost efficiency. As such, we are actively evaluating potential transactions to deleverage our balance sheet and manage our liquidity, which could include reducing existing debt through debt exchanges, debt repurchases and other modifications. In the event we execute such a strategic transaction, we expect that we will recognize a significant amount of cancellation of debt income (CODI), which will be allocated to our unitholders at the time of such transaction.

The amount of CODI generally will be equal to the excess of the adjusted issue price of the restructured debt over the value of the consideration received by debtholders in exchange for the debt. 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.

CODI with respect to any future transaction undertaken by us will be allocated to our unitholders of record (as applicable) on the first day of the month on which such a strategic transaction closes (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.

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.

Failure to maintain the continued listing standards of NASDAQ could result in delisting of our units, which could negatively impact the market price and liquidity of our units and our ability to access the capital markets.

Our units are listed on the NASDAQ Global Market (“NASDAQ”) and the continued listing of our units on NASDAQ is subject to our ability to comply with NASDAQ’s continued listing requirements, including, among other things, a minimum closing bid price requirement of $1.00 per unit. On July 17, 2017, we received a letter from the Listing Qualifications Department of NASDAQ notifying us that our units closed below the $1.00 per unit minimum bid price required by NASDAQ Listing Rule 5450(a)(1) for 30 consecutive business days and that we have a period of 180 calendar days in which to regain compliance.

We are considering options to regain compliance. If we are unable to regain compliance, however, any delisting from NASDAQ could result in even further reductions in our price per unit, substantially limit the liquidity of our units, and materially adversely affect our ability to raise capital or pursue strategic restructuring, refinancing or other transactions on acceptable terms, or at all. Delisting from the NASDAQ could also have other negative results, including the potential loss of institutional investor interest and fewer business development opportunities.

There is no assurance that we will continue to maintain compliance with NASDAQ continued listing standards. Our business has been and may continue to be affected by worldwide macroeconomic factors, which include uncertainties in the credit and capital markets as well as with respect to commodity prices. External factors that affect our unit price, such as liquidity requirements of our investors, as well as our performance, could impact our market capitalization, revenue and operating results, which, in turn, affect our ability to comply with the NASDAQ’s listing standards. The NASDAQ has the ability to suspend trading in our units or remove our units from listing on the NASDAQ if in the opinion of the exchange: (a) the financial condition and/or operating results of the Company appear to be unsatisfactory; (b) it appears that the extent of public distribution or the aggregate market value of our units has become so reduced as to make further dealings on the exchange inadvisable; (c) we have sold or otherwise disposed of our principal operating assets, or have ceased to be an operating company; (d) we have failed to comply with our listing agreements with the exchange; or (e) any other event shall occur or any condition shall exist which makes further dealings on the exchange unwarranted.

ITEM 2. UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS

None.

ITEM 3. DEFAULTS UPON SENIOR SECURITIES

None.

ITEM 4. MINE SAFETY DISCLOSURES

Not applicable.

ITEM 5. OTHER INFORMATION

None.

ITEM 6. EXHIBITS

The exhibits listed below are filed or furnished as part of this report: 

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

EXHIBIT INDEX