Harvest Oil & Gas Corp. - Quarter Report: 2015 September (Form 10-Q)

UNITED STATES SECURITIES AND EXCHANGE COMMISSION  

Washington, D.C. 20549 

Form 10-Q 

For the quarterly period ended September 30, 2015 

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: 

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 October 30, 2015, the registrant had 48,871,399 common units outstanding.

Table of Contents   

PART I. FINANCIAL INFORMATION

ITEM 1. FINANCIAL STATEMENTS

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 indirect 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 an indirect 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.

With the sale of our interest in Cardinal Gas Services, LLC (“Cardinal”) in October 2014 and the sale of our interest in Utica East Ohio Midstream LLC (“UEO”) in June 2015, we no longer operate in the midstream segment, and we have reclassified our condensed consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations (see Note 10). We now 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.

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 Annual Report on Form 10–K for the year ended December 31, 2014.

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.

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 primarily 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 $2.3 million and $2.8 million in the three months ended September 30, 2015 and 2014, respectively, and $9.4 million and $10.9 million in the nine months ended September 30, 2015 and 2014, respectively. These costs are included in “General and administrative expenses” in our unaudited condensed consolidated statements of operations.

As of September 30, 2015, there was $14.7 million of total unrecognized compensation cost related to unvested phantom units which is expected to be recognized over a weighted average period of 2.4 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. We recognized compensation cost related to these performance units of $0.2 million in the nine months ended September 30, 2015 and $1.5 million and $4.4 million in the three months and nine months ended September 30, 2014, respectively. 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. 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 September 30, 2015, we had entered into commodity contracts 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 September 30, 2015 and December 31, 2014, we were not required to post any collateral nor did we hold any collateral associated with our derivatives.

NOTE 4. IMPAIRMENT OF OIL AND NATURAL GAS PROPERTIES

We evaluate our proved oil and natural gas properties and related equipment and facilities for impairment whenever events or changes in circumstances indicate that the carrying amounts of such properties may not be recoverable. The determination of recoverability is made based upon estimated undiscounted future net cash flows. The amount of impairment loss, if any, is determined by comparing the fair value, as determined by a discounted cash flow analysis, with the carrying value of the related asset. We recorded impairment charges of $15.2 million and $73.3 million in the three months and nine months ended September 30, 2015, respectively, related to proved oil and natural gas properties (see Note 5).

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

Unproved oil and natural gas properties are assessed periodically on a property–by–property basis, and any impairment in value is recognized. We recorded impairment charges of $0.6 million and $48.9 million in the three months and nine months ended September 30, 2015 related to unproved oil and natural gas properties, of which $0.6 million and $48.4 million in the three months and nine months ended September 30, 2015, respectively, related to a change in our development plans for acreage in the Utica Shale.

NOTE 5. FAIR VALUE MEASUREMENTS

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 nine months ended September 30, 2015.

Nonrecurring Basis

In the three months and nine months ended September 30, 2015, as a result of a reduction in estimated future net cash flows primarily caused by lower oil, natural gas and natural gas liquids prices, we recognized $15.2 million and $73.3 million, respectively, of impairment charges to write down oil and natural gas properties to their fair value of $10.4 million and $31.4 million in the three months and nine months ended September 30, 2015, respectively.

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 proved reserves, appropriate risk–adjusted discount rates and other relevant data. 

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued) 

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 $352.5 million and $427.5 million at September 30, 2015 and December 31, 2014, respectively, which differs from the carrying value of $499.5 million and $499.4 million at September 30, 2015 and December 31, 2014, 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 September 30, 2015 and December 31, 2014, $1.9 million of our ARO is classified as current and is included in “Accounts payable and accrued liabilities” in our unaudited condensed consolidated balance sheets.

NOTE 7. LONG–TERM DEBT

Credit Facility

As of September 30, 2015, 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. The facility requires the maintenance of a current ratio (as defined in the facility) of greater than 1.0 and a ratio of senior secured debt to earnings plus interest expense, taxes, depreciation, depletion and amortization expense and exploration expense (“EBITDAX”) of no greater than 3.5 to 1.0. As of September 30, 2015, 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 3.86% and 2.99% at September 30, 2015 and 2014, respectively).

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

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 September 30, 2015, the borrowing base under the facility was $500.0 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.

As of September 30, 2015, we had no amounts outstanding under the facility. As of December 31, 2014, we had $531.0 million outstanding under the facility.

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.

The aggregate carrying amount of our senior notes due 2019 was $499.5 million and $499.4 million at September 30, 2015 and December 31, 2014, respectively.

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 September 30, 2015 or December 31, 2014.

NOTE 9. OWNERS’ EQUITY

Units Outstanding

At September 30, 2015, owners’ equity consists of 48,871,399 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest.

Issuance of Units

In the nine months ended September 30, 2015, we issued 0.3 million common units related to the vesting of equity–based awards. In conjunction with the vesting of these units, we received a contribution of $0.1 million by our general partner to maintain its 2% interest in us.

Cash Distributions

The following sets forth the distributions we paid during the nine months ended September 30, 2014:

On October 29, 2015, the board of directors of EV Management declared a $0.50 per unit distribution for the third quarter of 2015 on all outstanding units. The distribution of $25.2 million is to be paid on November 13, 2015 to unitholders of record at the close of business on November 9, 2015.

NOTE 10. DISCONTINUED OPERATIONS

Our midstream segment, which consisted of our investments in UEO and Cardinal, was engaged in the construction and operation of natural gas processing, natural gas liquids fractionation, connecting pipeline infrastructure and gathering systems to serve production in the Utica Shale area in Ohio. In October 2014, we sold our interest in Cardinal. In June 2015, we sold our interest in UEO and received net proceeds of $572.2 million and recognized a gain of $246.7 million. This gain is included in “Income from discontinued operations” for the nine months ended September 30, 2015.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

As a result of the reduction in the borrowing base under our facility upon the sale of our interest in UEO, we were required to repay $25.0 million of outstanding borrowings. Accordingly, $1.5 million of interest related to this $25.0 million and the write off of deferred financing costs related to the reduction in the borrowing base have been allocated to “Income from discontinued operations.”

We have reclassified our unaudited condensed consolidated financial statements for all periods presented to reflect the operations of our midstream segment as discontinued operations. Accordingly, in our unaudited condensed consolidated balance sheets, amounts previously included in “Investments in unconsolidated affiliates” have been reclassified to ”Assets held for sale” and, in our unaudited condensed consolidated statement of operations, amounts previously included in “Equity in income of unconsolidated affiliates” have been reclassified to “Income from discontinued operations.”

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. NET (LOSS) INCOME PER LIMITED PARTNER UNIT

The following sets forth the calculation of net (loss) income per limited partner unit:

As of September 30, 2015, there are no unearned performance units outstanding. Unearned performance units totaling 0.2 million units were not included in the computation of diluted net (loss) income per limited partner unit for the three months and nine months ended September 30, 2014 because the effect would have been anti–dilutive.

NOTE 12. RELATED PARTY TRANSACTIONS

Pursuant to an omnibus agreement, we paid EnerVest $3.3 million and $3.1 million in the three months ended September 30, 2015 and 2014, respectively, and $9.9 million and $9.1 million in the nine months ended September 30, 2015 and 2014, 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.

EV Energy Partners, L.P. 

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

We have entered into operating agreements with EnerVest whereby a 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 $3.5 million and $3.9 million in the three months ended September 30, 2015 and 2014, respectively, and $11.3 million and $12.2 million in the nine months ended September 30, 2015 and 2014, 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.

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 April 2015, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2015–03, Interest – Imputation of Interest. This ASU changes the presentation of debt issuance costs in financial statements. Under ASU 2015–03, an entity presents such costs in the balance sheet as a direct deduction from the related debt liability rather than as an asset. The provisions of ASU 2015–03 are applicable to annual reporting periods beginning after December 15, 2015 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.

EV Energy Partners, L.P.

Notes to Unaudited Condensed Consolidated Financial Statements (continued)

In April 2015, the FASB issued ASU No. 2015–06, Effects on Historical Earnings per Unit of Master Limited Partnership Dropdown Transactions. ASU 2015–06 specifies that for purposes of calculating historical earnings per unit under the two class method, the earnings (losses) of a transferred business before the date of a dropdown transaction should be allocated entirely to the general partner. In addition, qualitative disclosures about how the rights to the earnings (losses) differ before and after the dropdown transaction occurs for purposes of computing earnings per unit under the two class method are also required. The provisions of ASU 2015–06 are applicable to annual reporting periods beginning after December 15, 2015 and interim periods within those annual periods. We will adopt this ASU should we enter into a dropdown transaction.

In August 2015, the FASB issued ASU No. 2015–14, Deferral of the Effective Date, to defer the effective date of ASU 2014–09, Revenue from Contracts with Customers, for one year. The provisions of ASU 2014–09 are now applicable to annual reporting periods beginning after December 15, 2017 and interim periods within those annual periods. We have not yet determined the effect that adopting this ASU will have on our unaudited condensed consolidated financial statements.

In September 2015, the FASB issued ASU 2015–16, Simplifying the Accounting for Measurement Period Adjustments. To simplify the accounting for adjustments made to provisional amounts, ASU 2015–16 requires that the acquirer recognize adjustments to provisional amounts that are identified during the measurement period in the reporting period in which the adjustment amount is determined. The acquirer is required to also record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date.  In addition an entity is required to present separately on the face of the income statement or disclose in the notes to the financial statements the portion of the amount recorded in current period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The provisions of ASU 2015–16 are effective for fiscal years beginning after December 15, 2015 and interim periods within those fiscal years. We will adopt this ASU should we report provisional amounts for items in a business combination.

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2015 have had or are expected to have a material impact on our unaudited condensed consolidated financial statements.

NOTE 15. SUBSEQUENT EVENTS

In October 2015, we acquired oil and natural gas properties in the Appalachian Basin, San Juan Basin, Michigan and Austin Chalk from certain institutional partnerships managed by EnerVest for a combined cash consideration of $259.4 million, less the $25.9 million deposit that we made in September 2015. The deposit is included in “Other assets” in our unaudited condensed consolidated balance sheets. The purchase price is subject to customary purchase price adjustments.

In October 2015, we amended our credit facility to, among other things, increase the borrowing base to $625.0 million and amend our debt to EBITDAX ratio covenants as follows:

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

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, 2014.

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.

With the sale of our interest in Cardinal in October 2014 and the sale of our interest in UEO in June 2015, we no longer operate in the midstream segment. We now 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, 2014, our oil and natural gas properties were located in the Barnett Shale, the Appalachian Basin (which includes the Utica Shale), the Mid-Continent area in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Monroe Field in Northern Louisiana, the San Juan Basin, Michigan, Central Texas (which includes the Austin Chalk area), and the Permian Basin. As of December 31, 2014, we had estimated net proved reserves of 11.9 MMBbls of oil, 712.2 Bcf of natural gas and 36.1 MMBbls of natural gas liquids, or 1,000.5 Bcfe, and a standardized measure of $1,093.3 million.

CURRENT DEVELOPMENTS

In the nine months ended September 30, 2015, prices for oil, natural gas and natural gas liquids continue to remain low by historical standards. These low prices have affected our business in numerous ways, including:

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

In October 2015, we acquired oil and natural gas properties in the Appalachian Basin, San Juan Basin, Michigan and Austin Chalk from certain institutional partnerships managed by EnerVest for a combined cash consideration of $259.4 million, less the $25.9 million deposit that we made in September 2015. The purchase price is subject to customary purchase price adjustments.

In October 2015, we also amended our credit facility to, among other things, increase the borrowing base to $625.0 million and amend our debt to EBITDAX ratio covenants as follows:

BUSINESS ENVIRONMENT

Our primary business objective is to provide stability and growth in cash distributions per unit 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:

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 have continued to remain low through September 2015; prices for oil have remained at or below $62 per Bbl and natural gas prices have remained below $3.25 per MmBtu.

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 in recent months 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 recent months.

In order to mitigate the impact of these lower prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. Although we have entered into derivative contracts covering a portion of our future production through December 2017, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices that we can enter into derivative contracts for additional volumes in the future. We have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended period of depressed commodity prices would alter our acquisition and development plans, adversely affect our growth strategy and our ability to access additional capital in the capital markets and reduce the cash we have available to pay distributions. The decline in commodity prices that has occurred over the past year will likely require us to further reduce our quarterly distribution amount, absent a significant near-term increase in commodity prices.

The primary factors affecting our production levels are capital availability, including planned reductions in capital spending for 2015, 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.

Utica Shale

We hold approximately 173,000 net working interest acres in Pennsylvania and Ohio and an approximate 2% average ORRI in 880,000 gross acres in Ohio which we believe may be prospective for the Utica Shale. In addition, partnerships managed by EnerVest own acreage which may be prospective for the Utica Shale. Exploration and development activities targeting the Utica Shale are progressing, and it is possible that our estimates of the acreage in Ohio that we believe is prospective for the Utica Shale may change, perhaps materially, as additional exploration and development activities are conducted in the area. In the nine months ended September 30, 2015, we recognized a $48.4 million impairment charge related to a change in our development plans for acreage in the Utica Shale.

In mid–2012, we initiated the process for the monetization of a majority of our working interest acres related to the Utica Shale, and in 2013, we, along with certain institutional partnerships managed by EnerVest, signed agreements to divest a portion of our Utica Shale acreage. Through September 2015, we have closed on sales with proceeds of $45.6 million for these acres. We continue to pursue additional forms of monetizations, and we cannot at this time predict the type of transactions we may enter into or the type or amount of consideration we may receive. We may not be successful in our additional efforts to monetize the Utica Shale properties, it may take longer to complete the divestiture process than we expect, or we may decide to delay the monetization of all or a portion of the Utica Shale properties.

RESULTS OF OPERATIONS

Three Months Ended September 30, 2015 Compared with the Three Months Ended September 30, 2014

Net (loss) income for the three months ended September 30, 2015 was $(9.8) million compared with $42.6 million for the three months ended September 30, 2014. The significant factors in this change were (i) a $45.8 million decrease in oil, natural gas and natural gas liquids revenues; (ii) a $14.8 million increase in impairment of oil and natural gas properties; and (iii) a $6.3 million decrease in income from discontinued operations; offset by (iv) a $12.4 million decrease in operating costs and expenses (excluding impairment of oil and natural gas properties); and (v) a $2.6 million decrease in interest expense.

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2015 totaled $37.6 million, a decrease of $45.8 million compared with the three months ended September 30, 2014. This was the result of decreases of $39.7 million related to lower prices for oil, natural gas and natural gas liquids and $6.1 million related to decreased oil, natural gas and natural gas liquids production as a result of our decreased capital spending program.

Lease operating expenses for the three months ended September 30, 2015 decreased $4.1 million compared with the three months ended September 30, 2014 as the result of $3.2 million related to our decreased production and $0.9 million from a lower unit cost per Mcfe. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.59 in the three months ended September 30, 2015 compared with $1.64 in the three months ended September 30, 2014.

Production taxes, which are generally based on a percentage of our oil, natural gas and natural gas liquids revenues, for the three months ended September 30, 2015 decreased $1.7 million compared with the three months ended September 30, 2014 due to decreased oil, natural gas and natural gas liquids revenues. Production taxes for the three months ended September 30, 2015 were $0.10 per Mcfe compared with $0.19 per Mcfe for the three months ended September 30, 2014.

Depreciation, depletion and amortization (“DD&A”) for the three months ended September 30, 2015 decreased $2.2 million compared with the three months ended September 30, 2014 as the result of a $3.4 million decrease from lower production offset by an increase of $1.1 million from a higher DD&A rate. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for the three months ended September 30, 2015 was $1.66 per Mcfe compared with $1.59 per Mcfe for the three months ended September 30, 2014.

 General and administrative expenses for the three months ended September 30, 2015 totaled $8.6 million, a decrease of $1.1 million compared with the three months ended September 30, 2014. This decrease is the result of $1.9 million of lower equity compensation costs offset by $0.5 million of due diligence costs related to our October 2015 acquisitions and $0.3 million of higher fees paid to EnerVest under the omnibus agreement. General and administrative expenses were $0.61 per Mcfe in the three months ended September 30, 2015 compared with $0.60 per Mcfe in the three months ended September 30, 2014.

In the three months ended September 30, 2015, we incurred impairment charges of $15.8 million. Of this amount, $15.2 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 $0.6 million of leasehold impairments related to a change in our development plans for acreage in the Utica Shale. In the three months ended September 30, 2014, we incurred impairment charges of $0.9 million, all of which were related to leasehold impairment charges.

Gain (loss) on derivatives, net was $37.0 million for the three months ended September 30, 2015 compared with $37.5 million for the three months ended September 30, 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at September 30, 2015 for oil averaged $48.71 per Bbl compared with $61.99 at June 30, 2015, and the 12 month forward prices at September 30, 2015 for natural gas averaged $2.82 per MmBtu compared with $3.13 at June 30, 2015. The 12 month forward price at September 30, 2014 for oil averaged $87.16 per Bbl compared with $97.49 per Bbl at June 30, 2014, and the 12 month forward price at September 30, 2014 for natural gas averaged $3.92 per MmBtu compared with $4.07 at June 30, 2014.

Interest expense for the three months ended September 30, 2015 decreased $2.6 million compared with the three months ended September 30, 2014 due to $14.2 million from a lower weighted average long–term debt balance offset by $10.2 million from a higher weighted effective average interest rate and $1.4 million from a decrease in capitalized interest.

Income from discontinued operations for the three months ended September 30, 2015 decreased $6.3 million compared with the three months ended September 30, 2014 as we no longer operate in the midstream segment.

Nine Months Ended September 30, 2015 Compared with the Nine Months Ended September 30, 2014

Net income for the nine months ended September 30, 2015 was $92.6 million compared with $27.3 million for the nine months ended September 30, 2014. The significant factors in this change were (i) a $244.3 million increase in income from discontinued operations; (ii) a $54.7 million favorable change in gain (loss) on derivatives, net; and (iii) a $25.5 million decrease in operating costs and expenses (excluding impairment of oil and natural gas properties); offset by (iv) a $120.0 million increase in impairment of oil and natural gas properties and (v) a $137.9 million decrease in oil, natural gas and natural gas liquids revenues.

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2015 totaled $127.7 million, a decrease of $137.9 million compared with the nine months ended September 30, 2014. This was the result of decreases of $126.8 million related to lower prices for oil, natural gas and natural gas liquids and $11.1 million related to decreased oil and natural gas production as a result of our decreased capital spending program.

Lease operating expenses for the nine months ended September 30, 2015 decreased $8.2 million compared with the nine months ended September 30, 2014 as the result of $5.2 million related to our decreased production and $3.0 million from a lower unit cost per Mcfe. The lower unit cost per Mcfe reflects the downward trend in operating costs throughout the oil and natural gas industry. Lease operating expenses per Mcfe were $1.57 in the nine months ended September 30, 2015 compared with $1.63 in the nine months ended September 30, 2014.

Production taxes for the nine months ended September 30, 2015 decreased $4.8 million compared with the nine months ended September 30, 2014 due to lower oil, natural gas and natural gas liquids revenues. Production taxes for the nine months ended September 30, 2015 were $0.11 per Mcfe compared with $0.20 per Mcfe for the nine months ended September 30, 2014.

DD&A for the nine months ended September 30, 2015 decreased $2.2 million compared with the nine months ended September 30, 2014 due to $5.6 million from lower production offset by $3.4 million from a higher average DD&A rate per Mcfe. The higher average DD&A rate per Mcfe reflects the change that prices had on our reserves estimates. DD&A for the nine months ended September 30, 2015 was $1.68 per Mcfe compared with $1.61 per Mcfe for the nine months ended September 30, 2014.

General and administrative expenses for the nine months ended September 30, 2015 totaled $29.0 million, a decrease of $5.8 million compared with the nine months ended September 30, 2014. This decrease is primarily the result of (i) $5.5 million of lower equity compensation costs; (ii) $0.9 million of decreased compensation costs related to the vesting of our phantom units issued under our equity based compensation plan; and (iii) $1.0 million of costs incurred in the nine months ended September 30, 2014 related to the departure of a former officer; offset by (iv) $0.8 million of higher fees paid to EnerVest under the omnibus agreement and (v) $0.5 million of due diligence costs related to our October 2015 acquisitions. General and administrative expenses were $0.66 per Mcfe in the nine months ended September 30, 2015 compared with $0.73 per Mcfe in the nine months ended September 30, 2014.

In the nine months ended September 30, 2015, we incurred impairment charges of $122.2 million. Of this amount, $73.3 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 $48.9 million of leasehold impairments, of which $48.4 million related to a change in our development plans for acreage in the Utica Shale. In the nine months ended September 30, 2014, we incurred impairment charges of $2.3 million, of which $0.2 million related to a charge to write down assets held for sale to their fair value and $2.1 million related to leasehold impairment charges.

Gain (loss) on derivatives, net was $51.4 million for the nine months ended September 30, 2015 compared with $(3.3) million for the nine months ended September 30, 2014. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at September 30, 2015 for oil averaged $48.71 per Bbl compared with $56.46 at December 31, 2014, and the 12 month forward prices at September 30, 2015 for natural gas averaged $2.82 per MmBtu compared with $3.03 at December 31, 2014. The 12 month forward price at September 30, 2014 for oil averaged $87.16 per Bbl compared with $95.66 per Bbl at December 31, 2013, and the 12 month forward price at September 30, 2014 for natural gas averaged $3.92 per MmBtu compared with $4.19 at December 31, 2013.

Interest expense for the nine months ended September 30, 2015 increased $0.1 million compared with the nine months ended September 30, 2014 due to $7.4 million from a higher weighted effective average interest rate and $5.7 million from a decrease in capitalized interest offset by $13.0 million from a lower weighted average long–term debt balance.

Income from discontinued operations for the nine months ended September 30, 2015 increased $244.3 million compared with the nine months ended September 30, 2014. The significant factor in the increase was the $246.7 million gain recognized on the sale of our interest in 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, contributions to our midstream investments, distributions to our unitholders and general partner and working capital needs. For 2015, 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, pay distributions to our unitholders and general partner 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.

In the nine months ended September 30, 2015, prices for oil, natural gas and natural gas liquids continue to remain low by historical standards. A prolonged low price environment could adversely affect, among other things, our revenues, earnings, liquidity and reserves. In response to these continued lower prices, we have taken a number of actions to preserve our liquidity and financial flexibility, including:

In October 2015, we also amended our credit facility to, among other things, increase the borrowing base to $625.0 million and amend our debt to EBITDAX ratio covenants as follows:

Long–term Debt

As of September 30, 2015, 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 September 30, 2015, the borrowing base was $500.0 million, and we had no amounts outstanding. In October 2015, the borrowing base under the facility was increased to $625.0 million.

As of September 30, 2015, we have $500.0 million in aggregate principal amount outstanding of 8.0% senior notes due 2019. As of September 30, 2015, the aggregate carrying amount of the senior notes due 2019 was $499.5 million. We may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for equity securities in open market purchases, privately negotiated transactions or otherwise. Such repurchases or exchanges, if any, will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

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 September 30, 2015, we had $39.9 million of cash and short–term investments, which included $32.7 million of short–term investments.  With regard to our short–term investments, we invest in money market accounts with a major financial institution. 

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 September 30, 2015, 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 $118.8 million and $117.2 million in the nine months ended September 30, 2015 and 2014, respectively. The significant factors in the change were a $137.9 million decrease in our oil, natural gas and natural gas liquids revenues and a decrease in working capital, primarily related to lower accounts receivable as a result of decreased oil, natural gas and natural gas liquids prices at September 30, 2015 compared with September 30, 2014, offset by $106.5 million of increased cash settlements from our matured derivative contracts. The increased cash settlements are due to the impact of derivative contracts with less favorable terms that expired as of December 31, 2014.

Investing Activities

During the nine months ended September 30, 2015, cash flows used in investing activities from continuing operations totaled $49.3 million. This consisted of $58.7 million for additions to our oil and natural gas properties and $25.9 million related to a deposit on our October 2015 acquisition 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 $1.4 million in proceeds from the sales of oil and natural gas properties. Net cash flows provided by investing activities from discontinued operations of $572.2 million consisted of the proceeds from the sale of our interest in UEO.

During the nine months ended September 30, 2014, cash flows used in investing activities from continuing operations totaled $68.4 million. This consisted of $73.4 million for additions to our oil and natural gas properties offset by $7.4 million in proceeds from the sales of oil and natural gas properties. Net cash flows used in investing activities from discontinued operations of $105.2 million consisted of increases to our investment in unconsolidated affiliates.

Financing Activities

During the nine months ended September 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 $3.4 million related to the amendments of our credit facility and paid distributions of $75.7 million to holders of our common units, phantom units and our general partner. During the nine months ended September 30, 2014, we received $172.0 million from borrowings under our credit facility and paid distributions of $116.2 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, 2014.

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, natural gas and natural gas liquids production through December 2017. As of September 30, 2015, we have commodity contracts covering approximately 64% of our production attributable to our estimated net proved reserves from October 2015 through December 2017, as estimated in our reserve report prepared by third party engineers using prices, costs and other assumptions required by SEC rules. Subsequent to September 30, 2015, as a result of our October 2015 acquisitions, we now have commodity contracts covering approximately 50% of our production from October 2015 through December 2017. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

The fair value of our commodity contracts at September 30, 2015 was a net asset of $86.7 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 $22.8 million. Please see “Item 1. Condensed Consolidated Financial Statements (unaudited)” contained herein for additional information.

Interest Rate Risk

Our floating rate credit facility also exposes us to risks associated with changes in interest rates and as such, future earnings are subject to change due to changes in interest rates. If interest rates on our facility increased by 1%, interest expense for the nine months ended September 30, 2015 would have increased by approximately $2.4 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 September 30, 2015 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 September 30, 2015 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, 2014.

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