Harvest Oil & Gas Corp. - Quarter Report: 2016 June (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION  

Washington, D.C. 20549 

Form 10-Q 

For the quarterly period ended June 30, 2016 

OR 

Commission File Number 

001-33024  

EV Energy Partners, L.P. 

(Exact name of registrant as specified in its charter) 

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. 

YES þ NO ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). 

YES þ NO ¨

     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: 

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

YES ¨ NO þ 

As of July 29, 2016, the registrant had 49,055,214 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 the audited consolidated financial statements included in Item 8 of our Annual Report on Form 10–K for the year ended December 31, 2015. 

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.

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 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 consist of phantom units and performance units.  

We estimated the fair value of the phantom units using the Black–Scholes option pricing model. Compensation cost is recognized for these phantom units on a straight–line basis over the service period and is net of estimated forfeitures. These phantom units are subject to graded vesting over a four year period. We recognized compensation cost related to these phantom units of $1.4 million and $2.3 million in the three months ended June 30, 2016 and 2015, respectively, and $3.0 million and $7.1 million in the six months ended June 30, 2016 and 2015, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

As of June 30, 2016, there was $10.9 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.2 years.

In September 2011, we issued 0.3 million performance units to certain employees and executive officers of EV Management and its affiliates. These performance units were fully vested as of January 2015, and we recognized compensation cost related to these performance units of $0.2 million in the six months ended June 30, 2015. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 3. ACQUISITIONS

In October 2015, we made the following acquisitions from certain institutional partnerships managed by EnerVest, a related party:

These acquisitions were not accounted for as common control transactions as EnerVest does not control the institutional partnerships that sold the oil and natural gas properties.

As part of the acquisition of oil and natural gas properties in the San Juan Basin, we assumed an obligation to deliver approximately 2.4 billion cubic feet (“Bcf”) of natural gas through December 31, 2016 under previously existing volumetric production payment (“VPP”) agreements. Under these agreements, certain of these oil and natural gas properties are subject to fixed–term overriding royalty interests which had been conveyed to the VPP purchaser. While we are obligated under these agreements to produce and deliver to the purchaser its portion of future natural gas production from these oil and natural gas properties, we retain control of these oil and natural gas properties and rights to future development drilling. If production from the oil and natural gas properties subject to the VPP is inadequate to deliver the natural gas provided for in the VPP, we have an obligation to make up the shortfall in accordance with the provisions of the agreements. At June 30, 2016 and December 31, 2015, the remaining obligation under these agreements was approximately 0.9 Bcf and 1.9 Bcf, respectively, of natural gas.

At June 30, 2016 and December 31, 2015, we have recorded a liability of $2.0 million and $4.0 million, respectively, which is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets, for the cost to produce and deliver to the VPP purchasers their portion of future natural gas production from these oil and natural gas properties. In the three months and six months ended June 30, 2016, we recorded $0.04 million and $0.1 million, respectively, of accretion expense related to this VPP obligation.

We accounted for these acquisitions as business combinations. The following table reflects pro forma revenues and net income for the three months and six months ended June 30, 2015 as if these acquisitions had taken place on January 1, 2015. These unaudited pro forma amounts do not purport to be indicative of the results that would have actually been obtained during the periods presented or that may be obtained in the future.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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 “(Loss) gain on derivatives, net” in our unaudited condensed consolidated statements of operations.  

As of June 30, 2016, we had entered into commodity contracts with the following terms: 

 As of June 30, 2016, we had entered into interest rate swaps with the following terms: 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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, 2016 and December 31, 2015, we were not required to post any collateral nor did we hold any collateral associated with our derivatives. 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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. There were no changes in valuation techniques or related inputs in the three months ended June 30, 2016. 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Nonrecurring Basis

In the six months ended June 30, 2015, as a result of a reduction in estimated future net cash flows primarily caused by the continuing decrease in prices, we recognized a $58.2 million impairment charge to write down oil and natural gas properties to their fair value of $31.4 million.

The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from proved 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 derivatives and 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 2019 was $208.6 million and $211.9 million at June 30, 2016 and December 31, 2015, respectively, which differs from the carrying value of $341.7 million and $423.6 million at June 30, 2016 and December 31, 2015, respectively. The fair value of the senior notes due 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 both June 30, 2016 and December 31, 2015, $2.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 7. LONG–TERM DEBT 

Long–term debt, net consisted of the following:

Credit Facility 

As of June 30, 2016, 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. The facility allows for up to $35.0 million in cash, reduced by the amount of any quarterly distributions for the remainder of 2016, to be used for the redemption of our senior notes due 2019 (see below) and limits cash held by us to the greater of 5% of the current borrowing base or $30.0 million. We also may use up to $100.0 million of available borrowing capacity for letters of credit. As of June 30, 2016, we have a $0.4 million letter of credit outstanding. The facility requires the maintenance of certain financial covenants, and, as of June 30, 2016, we were in compliance with these financial covenants. 

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 4.58% and 3.50% at June 30, 2016 and 2015, 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. As of June 30, 2016, the borrowing base under the facility was $450.0 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.

8.0% Senior Notes due 2019 

Our senior notes due 2019 are fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of our existing 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.  

In the three months ended June 30, 2016, we redeemed $82.7 million of our senior notes due 2019 for $35.0 million, resulting in a gain on the early extinguishment of debt of $47.7 million.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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, 2016 or December 31, 2015.

NOTE 9. OWNERS’ EQUITY 

Units Outstanding 

At June 30, 2016, owners’ equity consists of 49,055,214 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. 

Issuance of Units 

In January 2016, we issued 0.2 million common units related to the vesting of equity–based awards.

Cash Distributions 

On January 25, 2016, the board of directors of EV Management declared a $0.075 per unit distribution for the fourth quarter of 2015 on all outstanding units. The distribution of $3.9 million was paid on February 12, 2016 to unitholders of record at the close of business on February 5, 2016.

In April 2016, the board of directors of EV Management announced that it had elected to suspend distributions for the first quarter of 2016. The board of directors also elected to suspend distributions for the second quarter of 2016.

NOTE 10. DISCONTINUED OPERATIONS

In 2015, we reclassified our unaudited condensed consolidated financial statements to reflect the operations of our midstream segment as discontinued operations due to the sales of our interest in Cardinal Gas Services, LLC in October 2014 and our interest in Utica East Ohio Midstream LLC in June 2015.

Summarized financial information for our midstream segment is as follows:

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 11. EARNINGS PER LIMITED PARTNER UNIT 

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

NOTE 12. RELATED PARTY TRANSACTIONS 

Pursuant to an omnibus agreement, we paid EnerVest $4.0 million and $3.3 million in the three months ended June 30, 2016 and 2015, respectively, and $8.0 million and $6.6 million in the six months ended June 30, 2016 and 2015, 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 with EnerVest whereby a wholly owned subsidiary of 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. We reimbursed EnerVest approximately $4.6 million and $3.7 million in the three months ended June 30, 2016 and 2015, respectively, and $10.8 million and $7.8 million in the six months ended June 30, 2016 and 2015, 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.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

NOTE 13. OTHER SUPPLEMENTAL INFORMATION  

Supplemental cash flows and noncash transactions were as follows: 

Accounts payable and accrued liabilities consisted of the following:

NOTE 14. NEW ACCOUNTING STANDARDS  

In August 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–15, Presentation of Financial Statements – Going Concern. This ASU amends the accounting guidance for the presentation and disclosure of uncertainties about an entity’s ability to continue as a going concern. It requires management to evaluate and disclose whether there is substantial doubt about its ability to continue as a going concern. Management should consider relevant conditions or events that are known or reasonably known on the date the financial statements are issued. The provisions of ASU 2014–15 are applicable to the annual reporting period ending after December 15, 2016 and for annual periods and interim periods thereafter. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

In March 2016, the FASB issued ASU No. 2016–09, Compensation – Stock Compensation. 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. The provisions of ASU 2016–09 are applicable to annual reporting periods beginning after December 15, 2016 and interim periods within those annual periods. Early adoption is permitted for financial statements that have not yet been previously issued. We do not expect that adopting this ASU will have a material impact on our unaudited condensed consolidated financial statements.

No other new accounting pronouncements issued or effective during the six months ended June 30, 2016 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

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, 2015. 

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 December 31, 2015, our oil and natural gas properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, and the Permian Basin. As of December 31, 2015, we had estimated net proved reserves of 22.0 MMBbls of oil, 747.0 Bcf of natural gas and 36.3 MMBbls of natural gas liquids, or 1,096.7 Bcfe, and a standardized measure of $536.4 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 such prices have remained low into the six months ended June 30, 2016.

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 have fallen and are likely to continue to directionally follow the market for oil. Further, excess supply with higher volumes in storage has resulted in a further drop in pricing for natural gas liquids.

In the six months ended June 30, 2016, these low prices negatively affected our revenues, earnings and cash flows, and sustained low prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity. A further or extended decline in prices could also adversely have a significant 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, 2015 were $50.28 per Bbl of oil and $2.587 per MMBtu of natural gas. Had we used the current forward strip prices at December 31, 2015 through December 31, 2021, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 29% higher and that our reserves on an Mcfe basis would have been approximately 7% higher than our reserves calculated using SEC prices.

Our Response to the Current Price Environment

In response to continued depressed prices and the fact that we have less production hedged in 2016 and 2017 at lower prices relative to previous years, we have taken additional steps going forward into 2016 to continue to preserve our liquidity and financial flexibility. These steps include:

In April 2016, we entered into an amendment to our credit facility that, among other things:

In April 2016, the board of directors announced that it had elected to suspend distributions to unitholders and, since the adoption of this amendment in April 2016, we have repurchased $82.7 million of outstanding senior notes due 2019 for $35.0 million. This repurchase of our senior notes due 2019 at a discount to par created cancellation of debt income for our unitholders.

As of July 29, 2016, we have $280.0 million outstanding under our credit facility and $343.3 million of our senior notes due 2019 outstanding, for a total of $623.3 million, and we have over $172.8 million of liquidity between our borrowing base capacity and cash on hand.

Business Environment

Our primary business objective is to provide stability and growth in cash distributions per unit over time. We have currently suspended distributions to unitholders to conserve any excess cash to enable us to be able to pay a distribution at a future date. When we resume our distribution payments, the amount of cash we could distribute to our unitholders will principally depend 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. We have entered into derivative contracts covering a portion of our future production through December 2017; however, due to depressed commodity prices over the last 18 months, we have less production volumes hedged and the prices at which those volumes are hedged are at lower average prices than in the past. This has left us with a greater exposure to current commodity prices and has impacted cash flows from operations. 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 delay our ability to reinstate our quarterly distribution.

The primary factors affecting our production levels are capital availability, including planned reductions in capital spending for 2016, 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 future possible distributions.

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, 2016 Compared with the Three Months Ended June 30, 2015

Net (loss) income for the three months ended June 30, 2016 was $(29.0) million compared with $164.1 million for the three months ended June 30, 2015. The significant factors in this change were (i) a $250.4 million decrease in income from discontinued operations and (ii) a $26.3 million unfavorable change in loss (gain) on derivatives, offset by (iii) a $47.7 million gain on early extinguishment of debt and (iv) a $46.3 million decrease in impairment of oil and natural gas properties.

Oil, natural gas and natural gas liquids revenues for the three months ended June 30, 2016 totaled $42.4 million, a decrease of $1.4 million compared with the three months ended June 30, 2015. This was the result of a decrease of $9.9 million related to lower prices for oil and natural gas offset by increases of $8.1 million from increased oil, natural gas and natural gas liquids production and $0.4 million from higher natural gas liquids prices. 

Lease operating expenses for the three months ended June 30, 2016 increased $2.2 million compared with the three months ended June 30, 2015 as the result of $5.0 million from increased production offset by $2.8 million from a lower unit cost per Mcfe. Lease operating expenses were $1.42 per Mcfe in the three months ended June 30, 2016 compared with $1.61 per Mcfe in the three months ended June 30, 2015.  

Depreciation, depletion and amortization (“DD&A”) for the three months ended June 30, 2016 increased $6.3 million compared with the three months ended June 30, 2015 as a result of $6.1 million from increased production and $0.2 million from a higher unit cost per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A was $1.73 per Mcfe in the three months ended June 30, 2016 compared with $1.71 per Mcfe in the three months ended June 30, 2015.  

General and administrative (“G&A”) expenses for the three months ended June 30, 2016 totaled $8.0 million, which was flat compared with the three months ended June 30, 2015. Included in G&A expenses for the three months ended June 30, 2016 were $1.0 million of lower equity compensation costs offset by $0.7 million of higher fees paid to EnerVest under the omnibus agreement. G&A expenses were $0.43 per Mcfe in the three months ended June 30, 2016 compared with $0.54 per Mcfe in the three months ended June 30, 2015.  

In the three months ended June 30, 2016, we incurred leasehold impairment charges of $2.0 million. In the three months ended June 30, 2015, we incurred leasehold impairment charges of $48.3 million, of which $47.9 million related to a change in our development plans for acreage in the Utica Shale.

(Loss) gain on derivatives, net was $(35.6) million for the three months ended June 30, 2016 compared with $(9.2) million for the three months ended June 30, 2015. This change was attributable to changes in future oil and natural gas prices and the impact of the expiration of derivative contracts with more favorable terms as of December 31, 2015. 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. The 12 month forward price at June 30, 2015 for oil averaged $61.99 per Bbl compared with $53.30 at March 31, 2015, and the 12 month forward prices at June 30, 2015 for natural gas averaged $3.13 per MmBtu compared with $2.91 at March 31, 2015.

Interest expense for the three months ended June 30, 2016 decreased $1.3 million compared with the three months ended June 30, 2015 due to $4.3 million from a lower weighted average long–term debt balance offset by $1.5 million from a higher weighted average effective interest rate and the write–off of $1.5 million of loan costs due to the reduction in the borrowing base and the redemption of the senior notes due 2019.

In the three months ended June 30, 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our senior notes due 2019 for $35.0 million.

In the three months ended June 30, 2015, income from discontinued operations was $250.4 million, which included the $246.7 million gain on the sale of UEO.

Six Months Ended June 30, 2016 Compared with the Six Months Ended June 30, 2015

Net (loss) income for the six months ended June 30, 2016 was $(58.0) million compared with $102.4 million for the six months ended June 30, 2015. The significant factors in this change were (i) a $255.5 million decrease in income from discontinued operations and (ii) a $40.1 million unfavorable change in loss (gain) on derivatives, offset by (iii) a $47.7 million gain on early extinguishment of debt and (iv) a $103.8 million decrease in impairment of oil and natural gas properties.

Oil, natural gas and natural gas liquids revenues for the six months ended June 30, 2016 totaled $80.1 million, a decrease of $10.0 million compared with the six months ended June 30, 2015. This was the result of a decrease of $24.2 million related to lower prices offset by an increase of $14.2 million from increased production. 

Lease operating expenses for the six months ended June 30, 2016 increased $7.6 million compared with the six months ended June 30, 2015 as the result of $9.5 million from increased production offset by $1.9 million from a lower unit cost per Mcfe. Lease operating expenses were $1.50 per Mcfe in the six months ended June 30, 2016 compared with $1.56 per Mcfe in the six months ended June 30, 2015.  

DD&A for the six months ended June 30, 2016 increased $8.6 million compared with the six months ended June 30, 2015 as a result of $10.3 million from increased production offset by $1.7 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 the decrease in the carrying value of our oil and natural gas properties from the impact of the impairments that were recognized in 2015. DD&A was $1.63 per Mcfe in the six months ended June 30, 2016 compared with $1.69 per Mcfe in the six months ended June 30, 2015.  

G&A expenses for the six months ended June 30, 2016 totaled $16.3 million, a decrease of $4.0 million compared with the six months ended June 30, 2015. This decrease is primarily the result of (i) $4.3 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 the six months ended June 30, 2015; (ii) a $1.4 million decrease in compensation costs, of which $0.8 million related to the vesting of our phantom units under our equity compensation plan; offset by (iii) $1.4 million of higher fees paid to EnerVest under the omnibus agreement. G&A expenses were $0.45 per Mcfe in the six months ended June 30, 2016 compared with $0.68 per Mcfe in the six months ended June 30, 2015.  

In the six months ended June 30, 2016, we incurred leasehold impairment charges of $2.7 million. In the six months ended June 30, 2015, we incurred impairment charges of $106.5 million. Of this amount, $58.2 million related to oil and natural gas properties that were written down to their fair value as determined based on the expected present value of the future net cash flows. Significant assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of our estimated reserves, appropriate risk – adjusted discount rates and other relevant data. The remainder of the impairment charges consisted of $48.3 million of leasehold impairments, of which $47.9 million related to a change in our development plans for acreage in the Utica Shale.

(Loss) gain on derivatives, net was $(25.8) million for the six months ended June 30, 2016 compared with $14.4 million for the six months ended June 30, 2015. This change was attributable to changes in future oil and natural gas prices and the impact of the expiration of derivative contracts with more favorable terms. 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. The 12 month forward price at June 30, 2015 for oil averaged $61.99 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at June 30, 2015 for natural gas averaged $3.13 per MmBtu compared with $3.03 at December 31, 2014.

Interest expense for the six months ended June 30, 2016 decreased $4.6 million compared with the six months ended June 30, 2015 due to $10.1 million from a lower weighted average long–term debt balance offset by $4.0 million from a higher weighted average effective interest rate and the write–off of $1.5 million of loan costs due to the reduction in the borrowing base and the redemption of the senior notes due 2019.

In the six months ended June 30, 2016, we recognized a $47.7 million gain on the early extinguishment of debt as we redeemed $82.7 million of our senior notes due 2019 for $35.0 million.

In the six months ended June 30, 2015, income from discontinued operations was $255.5 million, which included the $246.7 million gain on the sale of 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 working capital needs.

In response to continued depressed prices, we took a number of actions to preserve our liquidity and financial flexibility, and, as of July 29, 2016, we have over $172.8 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 volumes hedged and the prices at which those volumes are hedged are at lower average prices relative to previous years, we have taken additional steps going forward into 2016 to continue to preserve our liquidity and financial flexibility. These steps include:

For 2016, 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, 2016, we have a $1.0 billion credit facility that expires in February 2020. Borrowings under the facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of June 30, 2016, the borrowing base was $450.0 million, and we had $280.0 million outstanding.

As of June 30, 2016, we have $343.3 million in aggregate principal amount outstanding of our senior notes due 2019. As of June 30, 2016, the aggregate carrying amount of the senior notes due 2019 was $341.7 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, 2016, we had $2.8 million of cash on hand.  

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, 2016, 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 $14.4 million and $73.4 million in the six months ended June 30, 2016 and 2015, respectively. The significant factors in the change were $26.0 million of decreased cash settlements from our matured derivative contracts, an $11.7 million federal tax payment related to the conversion of an acquired corporation to a single member LLC, a $10.6 million decrease in total revenues and a $7.6 million increase in lease operating expenses.

Investing Activities

During the six months ended June 30, 2016, we spent $13.0 million for additions to our oil and natural gas properties and received $2.4 million from the sale of certain oil and natural gas wells and $2.5 million in cash settlements from acquired derivative contracts. During the six months ended June 30, 2015, cash flows used in investing activities from continuing operations totaled $(10.3) million. This consisted of $44.9 million for additions to our oil and natural gas properties offset by $33.8 million from the release of cash deposited with a qualified intermediary to facilitate like–kind exchange transactions pursuant to Section 1031 of the Internal Revenue Code and $0.8 million in proceeds from the sales of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $572.2 million consisted of the proceeds from the sale of our interest in Utica East Ohio Midstream LLC (“UEO”).

Financing Activities

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.

During the six months ended June 30, 2015, we repaid $561.0 million of borrowings under our credit facility with proceeds from the sale of our investment in UEO and the release of our restricted cash. We also received $30.0 million from borrowings under our credit facility, incurred loan costs of $3.3 million related to the amendment of our credit facility and paid distributions of $50.5 million to holders of our common units, phantom units and our general partner.

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, 2015. 

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 December 2017. As of June 30, 2016, we have commodity contracts covering approximately 83% of our production attributable to our estimated net proved reserves from July 2016 through December 2017, 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, 2016 was a net asset of $9.2 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 $19.7 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 six months ended June 30, 2016 would have increased by approximately $1.3 million. The fair value of our interest rate swaps at June 30, 2016 was a liability of $2.5 million. A 1% change in interest rates with all other factors held constant would result in a change in the fair value (generally correlated to our estimated future net cash flows from such interest rate swaps) of our interest rate swaps of approximately $1.9 million. 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, 2016 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, 2016 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

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, 2015.

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 

+ Filed herewith