UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10-Q

 

þQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

For the quarterly period ended September 30, 2018

OR

 

¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

 

Commission File Number

001-33024

 

Harvest Oil & Gas Corp.

(Exact name of registrant as specified in its charter)

 

Delaware
(State or other jurisdiction
of incorporation or organization)
  83–0656612
(I.R.S. Employer Identification No.)
     
1001 Fannin, Suite 750, Houston, Texas
(Address of principal executive offices)
  77002
(Zip Code)

 

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 every Interactive Data File required to be submitted 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 such files). 

YES þ NO ¨

 

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

 

Large accelerated filer ¨   Accelerated filer ¨   Non-accelerated filer þ   Smaller reporting company ¨
Emerging growth company ¨            

 

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

 

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

YES ¨ NO þ

 

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Sections 12, 13 or 15(d) of the Securities Exchange Act of 1934 subsequent to the distribution of securities under a plan confirmed by a court.

YES  þ    NO  ¨

 

As of November 13, 2018, the registrant had 10,042,468 shares of common stock, par value of $0.01 per share, outstanding.

 

 

 

 

 

  

Table of Contents

 

  PART I. FINANCIAL INFORMATION  
     
Item 1. Condensed Consolidated Financial Statements (Unaudited) 2
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations 32
Item 3. Quantitative and Qualitative Disclosures About Market Risk 43
Item 4. Controls and Procedures 44
     
  PART II. OTHER INFORMATION  
     
Item 1. Legal Proceedings 44
Item 1A. Risk Factors 44
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 45
Item 3. Defaults Upon Senior Securities 45
Item 4. Mine Safety Disclosures 45
Item 5. Other Information 45
Item 6. Exhibits 45
     
Signatures 47

 

 1 

 

  

PART I. FINANCIAL INFORMATION 

 

ITEM 1. CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

 

Harvest Oil & Gas Corp. 

Condensed Consolidated Balance Sheets 

(In thousands, except number of shares/units) 

(Unaudited) 

 

   Successor   Predecessor 
   September 30,   December 31, 
   2018   2017 
ASSETS          
Current assets:          
Cash and cash equivalents  $5,693   $4,896 
Equity securities   63,042    - 
Accounts receivable:          
Oil, natural gas and natural gas liquids revenues   52,340    47,694 
Other   2,572    78 
Derivative asset   -    3,052 
Other current assets   1,960    5,713 
Total current assets   125,607    61,433 
           
Oil and natural gas properties, net of accumulated depreciation, depletion and amortization; September 30, 2018, $7,551; December 31, 2017, $1,191,559   415,260    1,375,527 
Other assets   4,679    4,845 
Total assets  $545,546   $1,441,805 
           
LIABILITIES AND EQUITY          
Current liabilities:          
Accounts payable and accrued liabilities:          
Third party  $27,671   $43,817 
Related party   -    4,194 
Derivative liability   18,313    396 
Current portion of long-term debt   -    605,549 
Total current liabilities   45,984    653,956 
           
Asset retirement obligations   115,769    158,793 
Long–term debt, net   133,000    - 
Long–term derivative liability   10,495    - 
Other long–term liabilities   1,022    1,044 
           
Commitments and contingencies (Note 11)          
           
Mezzanine equity   49    - 
           
Stockholders’ / owners’ equity:          
Predecessor common unitholders – 49,368,869 units issued and outstanding as of December 31, 2017   -    648,371 
Predecessor general partner interest   -    (20,359)
Successor common stock – $0.01 par value; 65,000,000 shares authorized; 10,054,816 shares issued and 10,042,468 shares outstanding as of September 30, 2018   100    - 
Successor additional paid-in capital   249,672    - 
Successor treasury stock at cost – 12,348 shares at September 30, 2018   (247   - 
Successor retained earnings (accumulated deficit)   (10,298)   - 
Total stockholders’ / owners’ equity   239,227    628,012 
Total liabilities and equity  $545,546   $1,441,805 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 2 

 

  

Harvest Oil & Gas Corp. 

Condensed Consolidated Statements of Operations 

(In thousands, except per share/unit data) 

(Unaudited) 

 

   Successor   Predecessor 
   Three Months   Three Months 
   Ended   Ended 
   September 30, 2018   September 30, 2017 
Revenues:          
Oil, natural gas and natural gas liquids revenues  $68,407   $52,022 
Transportation and marketing–related revenues   559    629 
Total revenues   68,966    52,651 
           
Operating costs and expenses:          
Lease operating expenses   28,281    26,608 
Cost of purchased natural gas   393    444 
Dry hole and exploration costs   21    135 
Production taxes   2,973    2,573 
Accretion expense on obligations   2,345    1,905 
Depreciation, depletion and amortization   7,860    21,710 
General and administrative expenses   7,673    7,912 
Impairment of oil and natural gas properties   2,565    32 
Gain on sales of oil and natural gas properties   (28)   (876)
Total operating costs and expenses   52,083    60,443 
           
Operating income (loss)   16,883    (7,792)
           
Other income (expense), net:          
Loss on derivatives, net   (26,423)   (152)
Interest expense   (3,967   (10,092)
Gain on equity securities   4,830    - 
Other income (expense), net   (111)   68 
Total other income (expense), net   (25,671)   (10,176)
           
Reorganization items, net   (972)   - 
           
Loss before income taxes   (9,760)   (17,968)
           
Income tax benefit   -    80 
           
Net loss  $(9,760)  $(17,888)
           
Basic and diluted earnings per share / unit:          
Net loss  $(0.97)  $(0.36)
           
Weighted average common shares / units outstanding (basic and diluted)   10,028    49,369 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 3 

 

  

Harvest Oil & Gas Corp. 

Condensed Consolidated Statements of Operations 

(In thousands, except per share/unit data) 

(Unaudited)

 

   Successor   Predecessor 
   Four Months   Five Months   Nine Months 
   Ended   Ended   Ended 
   September 30, 2018   May 31, 2018   September 30, 2017 
Revenues:               
Oil, natural gas and natural gas liquids revenues  $89,942   $110,307   $163,745 
Transportation and marketing–related revenues   744    724    1,945 
Total revenues   90,686    111,031    165,690 
                
Operating costs and expenses:               
Lease operating expenses   37,656    45,372    76,782 
Cost of purchased natural gas   522    557    1,384 
Dry hole and exploration costs   64    122    190 
Production taxes   3,943    5,343    7,828 
Accretion expense on obligations   3,134    3,176    5,774 
Depreciation, depletion and amortization   10,590    46,196    70,221 
General and administrative expenses   9,702    15,648    21,631 
Restructuring costs   -    5,211    - 
Impairment of oil and natural gas properties   2,565    3    68,016 
(Gain) loss on sales of oil and natural gas properties   (47)   5    (911)
Total operating costs and expenses   68,129    121,633    250,915 
                
Operating income (loss)   22,557    (10,602)   (85,225)
                
Other income (expense), net:               
Gain (loss) on derivatives, net   (30,655   444    20,588 
Interest expense   (5,166)   (13,652)   (30,501)
Gain on equity securities   4,830    -    - 
Other income (expense), net   (84)   776    1,149 
Total other income (expense), net   (31,075)   (12,432)   (8,764)
                
Reorganization items, net   (1,780)   (587,325)   - 
                
Loss before income taxes   (10,298)   (610,359)   (93,989)
                
Income tax (expense) benefit   -    (166)   109 
                
Net loss  $(10,298)  $(610,525)  $(93,880)
                
Basic and diluted earnings per share / unit:               
Net loss  $(1.03)  $(12.12)  $(1.86)
                
Weighted average common shares / units outstanding (basic and diluted)   10,021    49,369    49,353 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 4 

 

  

Harvest Oil & Gas Corp.

Condensed Consolidated Statements of Changes in Owners’ Equity (Predecessor) 

(In thousands)

(Unaudited)

 

   Common
Unitholders
   General
Partner
Interest
   Total Owners'
Equity
 
Balance, December 31, 2017 (Predecessor)  $648,371   $(20,359)  $628,012 
Contribution from general partner   -    40    40 
Equity–based compensation   3,708    76    3,784 
Net loss   (598,314)   (12,211)   (610,525)
Issuance of common stock to Predecessor common unitholders   (11,967)   -    (11,967)
Issuance of warrants to Predecessor common unitholders   (9,345)   -    (9,345)
Cancellation of Predecessor common unitholders   (32,453)   -    (32,453)
Cancellation of Predecessor general partner interest   -    32,454    32,454 
Balance, May 31, 2018 (Predecessor)  $-   $-   $- 

 

Condensed Consolidated Statements of Equity (Successor) 

(In thousands)

(Unaudited)

 

                   Retained     
           Additional       Earnings   Total 
   Common Stock   Paid-in   Treasury   (Accumulated   Stockholders' 
   Shares   Amount   Capital   Stock   Deficit)   Equity 
Issuance of successor common stock to holders of the Senior Notes   9,500   $95   $227,271   $-   $-   $227,366 
Issuance of successor common stock to predecessor common unitholders   500    5    11,962    -    -    11,967 
Issuance of warrants   -    -    9,345    -    -    9,345 
Balance, May 31, 2018 (Successor)   10,000    100    248,578    -    -    248,678 
Net loss   -    -    -    -    (10,298)   (10,298)
Share–based compensation   -    -    1,094    -    -    1,094 
Restricted shares vested   55    -    -    -    -    - 
Purchase of treasury stock   (12)   -    -    (247)   -    (247)
Balance, September 30, 2018 (Successor)   10,043   $100   $249,672   $(247)  $(10,298)  $239,227 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 5 

 

  

Harvest Oil & Gas Corp.

Condensed Consolidated Statements of Cash Flows

(In thousands)

(Unaudited)

 

   Successor   Predecessor 
   Four Months   Five Months   Nine Months 
   Ended   Ended   Ended 
   September 30,   May 31,   September 30, 
   2018   2018   2017 
Cash flows from operating activities:               
Net loss  $(10,298)  $(610,525)  $(93,880)
Adjustments to reconcile net loss to net cash flows provided by operating activities:               
Accretion expense on obligations   3,134    3,176    5,774 
Depreciation, depletion and amortization   10,590    46,196    70,221 
Share–based compensation cost   1,144    3,784    3,290 
Impairment of oil and natural gas properties   2,565    3    68,016 
(Gain) loss on sales of oil and natural gas properties   (47)   5    (911)
Gain on equity securities   (4,830)   -    - 
(Gain) loss on derivatives, net   30,655    (444)   (20,588)
Cash settlements of matured derivative contracts   (1,847)   3,099    (2,196)
Reorganization items, net   -    573,304    - 
Other   780    248    820 
Changes in operating assets and liabilities:               
Accounts receivable   (2,014)   (3,518)   1,681 
Other current assets   314    1,853    (649)
Accounts payable and accrued liabilities   (4,183)   4,405    2,993 
Other, net   (38)   69    (235)
Net cash flows provided by operating activities   25,925    21,655    34,336 
                
Cash flows from investing activities:               
Acquisition of oil and natural gas properties   -    -    (61,400)
Additions to oil and natural gas properties   (22,307)   (29,727)   (9,344)
Reimbursements related to oil and natural gas properties   1,091    652    - 
Proceeds from sale of oil and natural gas properties   136,483    3    3,639 
Other   16    26    46 
Net cash flows provided by (used in) investing activities   115,283    (29,046)   (67,059)
                
Cash flows from financing activities:               
Repayment of long-term debt borrowings   (164,000)   -    (28,000)
Long–term debt borrowings   -    34,000    17,000 
Loan costs incurred   -    (2,813)   - 
Purchase of treasury stock   (247)   -    - 
Contributions from general partner   -    40    - 
Net cash flows provided by (used in) financing activities   (164,247)   31,227    (11,000)
                
Increase (decrease) in cash, cash equivalents and restricted cash   (23,039)   23,836    (43,723)
Cash, cash equivalents and restricted cash – beginning of period   28,732    4,896    57,633 
Cash, cash equivalents and restricted cash – end of period  $5,693   $28,732   $13,910 

 

See accompanying notes to unaudited condensed consolidated financial statements.

 

 6 

 

 

Harvest Oil & Gas Corp.

Notes to Unaudited Condensed Consolidated Financial Statements

 

NOTE 1. ORGANIZATION AND NATURE OF BUSINESS 

 

Nature of Operations 

 

Harvest Oil & Gas Corp. is a newly formed Delaware corporation and the successor reporting company to EV Energy Partners, L.P. (“EVEP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended. As used herein, the terms “Successor”, “Harvest”, or the “Company” refer to Harvest Oil & Gas Corp. and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. When referring to the “Predecessor” or the “Partnership” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to EVEP, the predecessor that was dissolved following the Effective Date (as defined below) of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made.

 

Unless the context requires otherwise, references to: (i) the “Predecessor’s general partner” and “EV Energy GP” refer to EV Energy GP, L.P., a Delaware limited partnership, the Predecessor’s general partner, which was dissolved following the Effective Date of the Plan; (ii) “EV Management” refers to EV Management, LLC, a Delaware limited liability company, the former general partner of the Predecessor’s general partner; and (iii) “EnerVest” refers to EnerVest, Ltd., a Texas limited partnership, the owner of EV Management.

 

Harvest is an independent oil and natural gas company that was formed in June 2018, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from September 2006 to June 2018. As discussed further in Note 2, on April 2, 2018, EV Energy Partners, L.P. (the “Debtor”), and 13 affiliated debtors (collectively, the “Debtors”) each filed a voluntary petition (the cases commenced thereby, the “Chapter 11 proceedings”) for relief under Chapter 11 of Title 11 of the United States Bankruptcy Code (“Chapter 11”) for bankruptcy protection in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) via Case No. 18-10814. The Debtors requested that their cases be jointly administered under Case No. 18-10814 to pursue the prepackaged plan of reorganization. During the pendency of the Chapter 11 proceedings, the Debtor continued to operate its businesses and manage its properties under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court as a “Debtors-in-Possession”. On May 17, 2018, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Modified Joint Prepackaged Plan of Reorganization (as amended, modified and supplemented from time to time, the “Plan”). The Plan became effective on June 4, 2018 (the “Effective Date”), when all remaining conditions to the effectiveness of the Plan were satisfied and the Company emerged from bankruptcy.

 

The Company operates one reportable segment engaged in the development and production of oil and natural gas properties, and all of its operations are located in the United States. From time to time, the Company may look to divest assets and use proceeds to repay bank debt, concentrate in existing positions or venture into new basins. The oil and natural gas properties of Harvest are located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin and the Monroe Field in Northern Louisiana.

 

Basis of Presentation 

 

The Company’s 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 (“GAAP”) have been condensed or omitted. The Company believes 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 and the related notes included in EVEP’s Annual Report on Form 10–K for the year ended December 31, 2017. 

 

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.

 

 7 

 

 

Bankruptcy Accounting

 

The unaudited condensed consolidated financial statements have been prepared as if the Company is a going concern and reflect the application of Accounting Standards Codification 852 Reorganizations (“ASC 852”). ASC 852 requires that the financial statements, for periods subsequent to the Chapter 11 filing, distinguish transactions and events that are directly associated with the reorganization from the ongoing operations of the business. Accordingly, certain expenses, gains and losses that were realized or incurred related to the bankruptcy proceedings are recorded in “Reorganization items, net” on the Company’s condensed consolidated statements of operations.

 

Upon emergence from bankruptcy on June 4, 2018, the Company elected to adopt and apply the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from Chapter 11 (“fresh start accounting”) effective May 31, 2018 to coincide with the timing of the Company’s normal accounting period close. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the condensed consolidated financial statements as of or after May 31, 2018, are not comparable with the condensed consolidated financial statements prior to that date. To facilitate the financial statement presentations, the Company refers to the reorganized company in these unaudited condensed consolidated financial statements and notes as the “Successor” for periods subsequent to May 31, 2018 and “Predecessor” for periods prior to June 1, 2018. Furthermore, the unaudited condensed consolidated financial statements and notes have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor. See Note 3 for additional information.

 

Use of Estimates

 

The preparation of financial statements in conformity with GAAP requires management to make estimates and judgments that affect the reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. The Company bases its estimates and judgments on historical experience and on various other assumptions and information that are believed to be reasonable under the circumstances. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as new events occur, as more experience is acquired, as additional information is obtained and as the Company’s operating environment changes. While Harvest believes that the estimates and assumptions used in the preparation of the unaudited condensed consolidated financial statements are appropriate, actual results could differ from those estimates.

 

New Accounting Standards

 

In May 2014, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) No. 2014–09, Revenue from Contracts with Customers (“ASU 2014-09”). This ASU, as amended, superseded virtually all of the revenue recognition guidance in generally accepted accounting principles in the United States. The core principle of the five–step model is that an entity will recognize revenue when it transfers control of goods or services to customers at an amount that reflects the consideration to which it expects to be entitled in exchange for those goods or services. Entities can choose to apply the standard using either the full retrospective approach or a modified retrospective approach. The Partnership implemented ASU 2014-09 as of January 1, 2018 using the modified retrospective method. The adoption of this ASU did not have a material impact on the Company’s unaudited condensed consolidated financial statements. See Note 4 for additional details about the impact upon adoption and related disclosures.

 

In January 2016, the FASB issued ASU No. 2016–01, Financial Instruments: Overall (Subtopic 825-10) (“ASU 2016-01”). This main objective of this ASU was to enhance the reporting model for financial instruments to provide users of financial statements with more decision-useful information. One of the provisions of this ASU was to require equity investments (except those accounted for under the equity method of accounting or those that result in consolidation of the investee) to be measured at fair value with changes in fair value recognized in net income. The Company implemented ASU 2016-01 as of January 1, 2018. Changes in fair value of the Company’s equity investments are included in “Gain on equity securities” in the unaudited condensed consolidated statements of operations. See Note 8 for additional details regarding the fair value measurement of the equity securities.

 

 8 

 

 

In February 2016, the FASB issued ASU No. 2016-02, Leases. The main objective of ASU 2016-02 is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. The main difference between previous GAAP and Topic 842 is the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases. ASU 2016-02 requires lessees to recognize assets and liabilities arising from leases on the balance sheet. ASU 2016-02 further defines a lease as a contract that conveys the right to control the use of identified property, plant, or equipment for a period of time in exchange for consideration. Control over the use of the identified asset means that the customer has both (1) the right to obtain substantially all of the economic benefit from the use of the asset and (2) the right to direct the use of the asset. ASU 2016-02 requires disclosures by lessees and lessors to meet the objective of enabling users of financial statements to assess the amount, timing, and uncertainty of cash flows arising from leases. In transition, lessees and lessors are required to recognize and measure leases at the beginning of the earliest period presented using a modified retrospective approach. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842), Land Easement Practical Expedient for Transition to Topic 842 (“ASU 2018-01”), which permits an entity an optional election to not evaluate under ASU 2016-02 those existing or expired land easements that were not previously accounted for as leases prior to the adoption of ASU 2016-02. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842), Targeted Improvements (“ASU 2018-11”), which permits an entity (i) to apply the provisions of ASU 2016-02 at the adoption date instead of the earliest period presented in the financial statements, and, as a lessor, (ii) to account for lease and nonlease components as a single component as the nonlease components would otherwise be accounted for under the provisions of ASU 2014-09. For public entities, ASU 2016-02 and other related ASUs are effective for financial statements issued for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years; early application is permitted. The Company is continuing to evaluate the impact of this standard on its financial statements and is continuing its assessment of ASU 2016-02 by implementing its project plan, evaluating certain operational and corporate policies and processes, further defining the population of leases under the revised definition and reviewing numerous contracts. The Company does not intend to early adopt this standard, but plans to apply the new standard for its interim and annual reporting periods starting January 1, 2019 using a modified retrospective approach. The Company also plans to elect the package of practical expedients within ASU 2016-02 that allows an entity to not reassess prior to the effective date (i) whether any expired or existing contracts are or contain leases, (ii) the lease classification for any expired or existing leases or (iii) initial direct costs for any existing leases. Additionally, the Company plans to elect the practical expedient under ASU 2018-01 and not evaluate existing or expired land easements not previously accounted for as leases prior to the effective date. The adoption of this standard will result in an increase in the assets and liabilities on the Company’s consolidated balance sheets. The quantitative impacts of the new standard are dependent on the leases in force at the time of adoption. As a result, the evaluation of the effect of the new standards will extend over future periods.

 

In August 2016, the FASB issued ASU No. 2016–15, Statement of Cash Flows. This ASU addresses certain cash flow issues with the objective of reducing the existing diversity in practice in how the cash receipts and cash payments are presented and classified in the statement of cash flows. The Partnership adopted ASU 2016–15 on January 1, 2018. The adoption of this ASU did not have a material impact on the Company’s unaudited condensed consolidated financial statements.

 

In November 2016, the FASB issued ASU No. 2016-18: Statement of Cash Flows– Restricted Cash. The main objective of ASU 2016-18 is to address the diversity that exists in the classification and presentation of changes in restricted cash on the statement of cash flows. The amendments in ASU 2016-18 require that a statement of cash flows explain the change during the period in the total of cash, cash equivalents and amounts generally described as restricted cash or restricted cash equivalents. Thus, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning of period and end of period total amounts shown on the statement of cash flows. The Partnership adopted ASU 2016-18 on January 1, 2018. The adoption of this ASU resulted in a change to the condensed consolidated statement of cash flows for the nine months ended September 30, 2017. For the nine months ended September 30, 2017, the $5.5 million cash and cash equivalents – beginning of year was revised to $57.6 million cash, cash equivalents and restricted cash – beginning of year and the net cash used in investing activities was increased from $15.0 million to $67.1 million.

 

In January 2017, the FASB issued ASU No. 2017-01, Business Combinations (Topic 805): Clarifying the Definition of a Business (“ASU 2017-01”). The main objective of ASU 2017-01 is to clarify the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. The amendments of this ASU provide a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired (or disposed of) is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. This screen reduces the number of transactions that need to be further evaluated. If the screen is not met, the amendments of this ASU (i) require that to be considered a business, a set must include, at a minimum, an input and a substantive process that together significantly contribute to the ability to create output and (ii) remove the evaluation of whether a market participant could replace missing elements. The Partnership adopted ASU 2017-01 on January 1, 2018, and the ASU will be applied prospectively to any acquisitions.

 

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In August 2018, the FASB issued ASU No. 2018-13: Fair Value Measurement (Topic 820): Disclosure Framework – Changes to the Disclosure Requirements for Fair Value Measurement (“ASU 2018-13”). The FASB issued ASU 2018-13 as part of its disclosure framework project. The amendments of this ASU modify the disclosure requirements on fair value measurements in Topic 820, Fair Value Measurement. ASU 2018-13 is effective for financial statements issued for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years; early application is permitted. We do not expect that adopting this ASU will have a material impact on our consolidated financial statements.

 

No other new accounting pronouncements issued or effective during the nine months ended September 30, 2018 have had or are expected to have a material impact on the unaudited condensed consolidated financial statements other than those disclosed in EVEP’s Annual Report on Form 10-K for the year ended December 31, 2017.

 

Subsequent Events

 

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

 

NOTE 2. EMERGENCE FROM VOLUNTARY REORGANIZATION UNDER CHAPTER 11

 

On March 13, 2018, the Debtors entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) holders (collectively, the “Supporting Noteholders”) of approximately 70% of the 8.0% senior unsecured notes due April 2019 (the “Senior Notes”) issued pursuant to that certain indenture, dated as of March 22, 2011 (as amended, restated, supplemented or otherwise modified from time to time, the “Indenture”), among EVEP, EV Energy Finance Corp., each of the guarantors party thereto, and Delaware Trust Company, as indenture trustee, that are signatories to the Restructuring Support Agreement; (ii) lenders under the Predecessor’s reserve-based lending facility, by and among EVEP, EV Properties, L.P., JPMorgan Chase Bank, N.A., as administrative agent, BNP Paribas and Wells Fargo, National Association, as co-syndication agents, the guarantors party thereto (the “credit facility”), and the lenders signatory thereto, initially constituting approximately 94%, but subsequently increased to 100%, of the principal amount outstanding thereunder; (iii) EnerVest; and (iv) EnerVest Operating, L.L.C. (“EnerVest Operating”). The Restructuring Support Agreement set forth, subject to certain conditions, the commitment of the Debtors and the consenting creditors to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring”).

 

On April 2, 2018 (the “Petition Date”), the Debtors each filed Chapter 11 proceedings for relief under Chapter 11 in the Bankruptcy Court. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re EV Energy Partners, L.P., et al., Case No. 18-10814.

 

On May 17, 2018, the Bankruptcy Court entered the Confirmation Order confirming the Debtors’ Plan.

 

On June 4, 2018, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession from April 2, 2018 through June 4, 2018. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

 

Plan of Reorganization

 

In accordance with the Plan, on the Effective Date:

 

·The Successor issued (i) 9,500,000 new shares of its common stock, par value $0.01 per share (“common stock”) pro rata to holders of the Senior Notes with claims allowed under the Plan; (ii) 500,016 shares of common stock pro rata to holders of units of EVEP prior to the Effective Date; (iii) 800,000 warrants (the “Warrants”) to purchase 800,000 shares of the Company’s common stock to holders of units of EVEP prior to the Effective Date exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common stock (including common stock as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common stock issuable under the Company’s Management Incentive Plan (the “MIP”)), at a per share exercise price of $37.48; (iv) 79,000 shares of 8% Cumulative Nonparticipating Redeemable Series A Preferred Stock (the “Series A Preferred Stock”) to its indirectly wholly-owned subsidiary EV Midstream, L.P. for consideration of $790,000; and (v) 21,000 shares of Series A Preferred Stock to one employee of the Company and one employee of EnerVest for consideration of services to the Company, which vest on the earlier of (i) June 4, 2019 or (ii) immediately prior to the consummation of a Sale Transaction as such term is defined in the Certificate of Designations, Preferences and Rights of the Series A Preferred Stock (the “Certificate of Designations”);

 

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·The holders of claims under the Predecessor’s credit facility received full recovery, consisting of (i) their pro rata share of the $1 billion new reserve-based revolving loan (the “Exit Credit Facility”), as further discussed in Note 10; (ii) cash in amount equal to the accrued but unpaid interest payable to such lenders under the credit facility as of the Effective Date; and (iii) unfunded commitments and letter of credit participation under the Exit Credit Facility equal to the unfunded commitments and letter of credit participation of such lender as of the Effective Date;

 

·The Senior Notes were cancelled and the Predecessor’s liability thereunder discharged, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Stock representing, in the aggregate, 95% of the New Common Stock on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants);

 

·The Predecessor’s common units were cancelled, and each common unitholder received its pro rata share of: (i) 5% of the New Common Shares and (ii) the Warrants;

 

·The holders of administrative expense claims, other priority claims and general unsecured creditors of the Predecessor received in exchange for their claims payment in full in cash or otherwise had their rights unimpaired under Title 11 of the United States Code;

 

·The Successor entered into a registration rights agreement (the “Registration Rights Agreement”) with certain recipients of shares of its common stock pursuant to which the Successor agreed to, among other things, file a shelf registration statement (the “Initial Shelf Registration Statement”) and use its reasonable best efforts to have the Initial Shelf Registration Statement declared effective as soon as possible after the date of its first Quarterly Report on Form 10-Q following the Effective Date;

 

·The Successor adopted the MIP, pursuant to which employees, directors, consultants and other service providers of the Company and its subsidiaries are eligible to receive stock options, stock appreciation rights, restricted stock, restricted stock units, other stock-based awards and cash-based awards. As of the Effective Date, an aggregate of 689,362 shares of common stock were reserved for issuance under the MIP, all of which may be granted in the form of incentive stock options;

 

·The terms of the Predecessor’s board of directors automatically expired on the Effective Date. The Successor formed a new five-member board of directors consisting of the Chief Executive Officer and two new members designated by certain parties to the Restructuring Support Agreement and two independent members; and

 

·General unsecured claims received, (i) if such claim was due and payable on or before the Effective Date, payment in full, in cash, or the unpaid portion of its allowed general unsecured claim, (ii) if such claim was not due and payable before the Effective Date, payment in the ordinary course, and (iii) other treatment, as may be agreed upon by the Debtors, the Supporting Noteholders and the holder of such general unsecured claim; and

 

·The Company converted from a limited partnership to a corporation.

 

NOTE 3. FRESH START ACCOUNTING

 

In connection with emergence from the Chapter 11 proceedings on the Effective Date, the Company applied the provisions of fresh start accounting, pursuant to ASC 852, Reorganizations (“ASC 852”), to its consolidated financial statements, which resulted in the Company becoming a new entity for financial reporting purposes. Harvest qualified for fresh start accounting as (i) the holders of existing voting common units of the Predecessor received less than 50% of the voting shares of the emerged entity and (ii) the reorganization value of assets immediately prior to confirmation was less than the post-petition liabilities and allowed claims. ASC 852 requires that fresh start accounting be applied when the Bankruptcy Court enters the Confirmation Order confirming the Plan, or as of a later date when all material conditions precedent to the effectiveness of the Plan are resolved, which was June 4, 2018. The Company elected to apply fresh start accounting effective May 31, 2018, to coincide with the timing of its normal accounting period close. The Company evaluated the events between May 31, 2018 and June 4, 2018 and concluded that the use of an accounting convenience date of May 31, 2018 did not have a material impact on the results of operations or financial position.

 

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Upon adoption of fresh start accounting, the reorganization value derived from the enterprise value was allocated to the Company’s assets and liabilities based on their fair values (except for deferred income taxes) in accordance with Accounting Standards Codification 805 Business Combinations (“ASC 805”). The amount of deferred income taxes recorded was determined in accordance with Accounting Standards Codification 740 Income Taxes (“ASC 740”). The Effective Date fair values of the Company’s assets and liabilities differed materially from their recorded values as reflected on the historical balance sheet of the Predecessor. The effects of the Plan and the application of fresh start accounting were reflected in the condensed consolidated financial statements as of May 31, 2018, and the related adjustments thereto were recorded on the condensed consolidated statement of operations for the five months ended May 31, 2018.

 

As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements subsequent to May 31, 2018, are not comparable to its condensed consolidated financial statements prior to May 31, 2018. References to “Successor” relate to the financial position and results of operations of the reorganized Company as of and subsequent to May 31, 2018. References to “Predecessor” relate to the financial position of the Company prior to, and results of operations through and including, May 31, 2018.

 

The Company’s condensed consolidated financial statements and related footnotes are presented with a black line division, which delineates the lack of comparability between amounts presented after May 31, 2018, and amounts presented on or prior to May 31, 2018. The Company’s financial results for future periods following the application of fresh start accounting will be different from historical trends and the differences may be material.

 

Reorganization Value

 

In the disclosure statement associated with the Plan, which was confirmed by the Bankruptcy Court, the Successor’s enterprise value was estimated to be within a range of $450 million to $550 million, with a midpoint estimate of approximately $500 million. Enterprise value represents the estimated fair value of a company’s interest-bearing debt, its stockholders’ equity and working capital. Based on the estimates and assumptions utilized in the fresh start accounting process, the Company estimated the Successor’s enterprise value to be approximately $524.6 million before the consideration of cash and cash equivalents on hand at the Effective Date. Reorganization value represents the fair value of the Successor’s total assets prior to the consideration of liabilities and is intended to approximate the amount a willing buyer would pay for the assets immediately after a restructuring. The reorganization value, which was derived from the Successor’s enterprise value, was allocated to the Company’s individual assets based on their estimated fair values.

 

The following table is a reconciliation of the enterprise value to the estimated fair value of the Successor’s common stock at the Effective Date (in thousands):

 

Enterprise Value  $524,596 
Plus: Cash and cash equivalents   21,082 
Less: Fair value of debt   (297,000)
Fair value of successor equity  $248,678 

 

The following table is a reconciliation of the enterprise value to the reorganization value of the Successor assets at the Effective Date (in thousands):

 

Enterprise Value  $524,596 
Plus: Cash and cash equivalents   21,082 
Plus: Other working capital liabilities   36,787 
Plus: Other long-term liabilities   121,041 
Reorganization value of Successor assets  $703,506 

 

Our assets consist primarily of producing oil and natural gas properties. The fair values of proved and unproved oil and natural gas properties were estimated using valuation techniques consistent with the income approach, converting future cash flows to a single discounted amount. The factors to determine fair value include, but are not limited to, estimates of: (i) economic reserves, (ii) future operating and development costs, (iii) future commodity prices and (iv) a market-based weighted average cost of capital. These inputs require significant judgments and estimates by the Company’s management at the time of the valuation and are the most sensitive and subject to change. The underlying commodity prices embedded in the Company’s estimated cash flows are the product of a process that incorporates forward commodity pricing, analyst pricing estimates and adjustments for estimated location and quality differentials, as well as other factors as necessary that the Company’s management believes will impact realizable prices. The fair value of support equipment and facilities were estimated using a cost approach, based on current replacement costs of the assets less depreciation based on the estimated economic useful lives of the assets and age of the assets.

 

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See below under the caption “Fresh Start Adjustments” for additional information regarding assumptions used in the valuation of the Company’s various other significant assets and liabilities.

 

Condensed Consolidated Balance Sheet

 

The adjustments included in the following condensed consolidated balance sheet reflect the effect of the transactions contemplated by the Plan (reflected in the column “Reorganization Adjustments”) as well as fair value and other required accounting adjustments resulting from the adoption of fresh start accounting (reflected in the column “Fresh Start Adjustments”). The explanatory notes provide additional information with regard to the adjustments recorded, the methods used to determine the fair values and significant assumptions.

 

   As of May 31, 2018 
       Reorganization   Fresh Start     
   Predecessor   Adjustments (1)   Adjustments   Successor 
ASSETS                    
Current assets:                    
Cash and cash equivalents  $35,020   $(13,938)(2)  $-   $21,082 
Restricted cash   -    7,650(3)    -    7,650 
Accounts receivable:                    
Oil, natural gas and natural gas liquids revenues   48,986    1,261(4)     -    50,247 
Related party   1,503    (1,503)(4)   -    - 
Other   800    -    -    800 
Other current assets   4,580    (527)(5)   (1,791)(12)   2,262 
Total current assets   90,889    (7,057)   (1,791)   82,041 
Oil and natural gas properties, net   1,355,504    -    (739,486)(13)   616,018 
Other assets   4,507    1,941(6)    (1,001)(14)   5,447 
Total assets  $1,450,900   $(5,116)  $(742,278)  $703,506 
                     
LIABILITIES AND EQUITY                    
Current liabilities:                    
Accounts payable and accrued liabilities  $34,922   $2,177(7)   $(312)(15)  $36,787 
Current portion of long-term debt   297,000    (297,000)(8)   -    - 
Total current liabilities   331,922    (294,823)   (312)   36,787 
Liabilities subject to compromise   356,066    (356,066)(9)   -    - 
Asset retirement obligations   161,661    -    (41,641)(15)   120,020 
Long–term debt, net   -    297,000(8)    -    297,000 
Other long–term liabilities   1,021    -    -    1,021 
Total liabilities   850,670    (353,889)   (41,953)   454,828 
Commitments and contingencies (Note 11)                    
Stockholders' / owners’ equity:                    
Predecessor common unitholders   621,144    65,175(10)    (686,319)(16)   - 
Predecessor general partner interest   (20,914)   34,920(10)    (14,006)(16)   - 
Successor common stock   -    100(11)    -    100 
Successor additional paid-in capital   -    248,578(11)    -    248,578 
Total stockholders' / owners’ equity   600,230    348,773    (700,325)   248,678 
Total liabilities and equity  $1,450,900   $(5,116)  $(742,278)  $703,506 

 

 

Reorganization Adjustments

 

(1)Reflects amounts recorded as of the Effective Date for the implementation of the Plan, including among other items, settlement of the Predecessor’s liabilities subject to compromise, cancellation of the Predecessor’s equity, issuance of the Successor New Common Shares and the Warrants, repayment of certain of Predecessor’s liabilities and settlement with holders of the Senior Notes.

  

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(2)Reflects the changes in cash and cash equivalents, including the following:

 

Funding of the professional fees escrow account  $(7,650)
Payment of debt issuance costs on the Successor Exit Credit Facility   (2,813)
Payment of professional fees   (1,591)
Payment of success fees   (1,573)
Payment of derivative settlement   (216)
Payment of accrued interest payable under the Predecessor credit facility   (135)
Transfer of funds from Predecessor's general partner   40 
Changes in cash and cash equivalents  $(13,938)

 

(3)Reflects the transfer of restricted cash to fund the professional fees escrow account.

 

(4)Primarily reflects the reclassification of the related party net receivable from EnerVest to a third party receivable as EnerVest is no longer a related party as result of the Restructuring. Also, reflects the cancellation of related party claims of $0.2 million with the general partner of EVEP as a result of the Debtor’s emergence from Chapter 11 bankruptcy proceedings.

 

(5)Represents the expense of certain prepaid professional fees as a result of the Debtor’s emergence from Chapter 11 bankruptcy proceedings.

 

(6)Reflects the capitalization of the deferred financing costs of $2.8 million related to the Successor’s Exit Credit Facility, offset by the write-off of $0.8 million of deferred financing costs related to the Predecessor’s credit facility.

 

(7)Net increase in Accounts payable and accrued liabilities reflects the following:

 

Recognition of payables for success fees  $4,086 
Recognition of payables for professional fees   32 
Payment of professional fees   (1,590)
Payment of derivative settlement   (216)
Payment of accrued interest payable under the Predecessor credit facility   (135)
Net increase in accounts payable and accrued liabilities  $2,177 

 

(8)Reflects the reclassification of $297.0 million in borrowings under the Exit Credit Facility to long-term debt.

 

(9)Settlement of liabilities subject to compromise and the resulting net gain were determined as follows:

 

Senior Notes  $343,348 
Accrued interest payable   12,718 
Total liabilities subject to compromise of Predecessor   356,066 
Issuance of common stock to holders of the Senior Notes   (227,366)
Gain on settlement of liabilities subject to compromise  $128,700 

 

The amount of disallowed interest during the period from the Petition Date through the Effective Date of emergence not included in the accrued interest payable in the table above was $4.7 million.

 

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(10)Reflects the cancellation of the Predecessor company common unitholders and general partner interest.

 

       General 
   Common   Partner 
   Unitholders   Interest 
Net gain from reorganization adjustments  $118,940   $2,426 
Contribution from general partner   -    40 
Issuance of common stock to Predecessor common unitholders   (11,967)   - 
Issuance of warrants to Predecessor common unitholders   (9,345)   - 
Cancellation of Predecessor common unitholders / general partner interest   (32,453)   32,454 
   $65,175   $34,920 

 

(11)Reflects the issuance of 10,000,016 shares of common stock at a par value of $0.01 per share in accordance with the Plan, and the issuance of 800,000 warrants in accordance with the Plan. The fair value of the Warrants was determined by using the Black-Scholes model and were reasonably estimated to be approximately $11.68 per share. See Note 13 for additional information on the issuance of the Successor’s Warrants.

 

Issuance of shares of Successor common stock at par value of $0.01 per share  $100 
Additional paid-in capital from issuance of Successor common stock   239,233 
Additional paid-in capital from issuance of Successor warrants   9,345 
Fair value of Successor equity  $248,678 

 

See Note 13 for additional information on the issuances of the Successor’s equity.

 

Fresh Start Adjustments

 

(12)Reflects the adjustment to write-down certain other current assets to fair value.

 

(13)Reflects a decrease of oil and natural gas properties, net. In determining the fair value of the oil and gas properties both the income and market approach were utilized and the accumulated depreciation, depletion and impairment was eliminated. The following table summarizes the components of oil and natural gas properties as of the Effective Date: based on the methodology discussed above and the elimination of accumulated depreciation, depletion and impairment. The fresh start adjustments to oil and natural gas properties, net are as follows:

 

   Successor   Predecessor 
   Fair Value   Historical Book Value 
Proved oil and natural gas properties  $547,136   $2,593,249 
Unproved oil and natural gas properties   68,882    - 
    616,018    2,593,249 
Accumulated depreciation, depletion and amortization   -    (1,237,745)
Net capitalized costs  $616,018   $1,355,504 

 

(14)Reflects the write-off of immaterial other assets not anticipated to have value to Harvest.

 

(15)Reflects a decrease of $42.0 million for asset retirement obligations. The fair value of asset retirement obligations was estimated using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation include estimates of: (i) plugging and abandonment costs per well based on existing regulatory requirements, (ii) remaining life per well, (iii) future inflation factors and (iv) a credit-adjusted risk free rate.

 

(16)Reflects the cumulative impact of the fresh start adjustments discussed above.

 

Reorganization Items, Net

 

The Company has incurred significant costs associated with the reorganization. These costs, which are expensed as incurred, are expected to significantly affect the Company’s results of operations. Reorganization items, net represent costs, gains and losses directly associated with the Chapter 11 proceedings since the Petition Date.

 

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The following table summarizes the components of reorganization items, net included in the accompanying unaudited condensed consolidated statements of operations:

 

   Successor   Predecessor 
   Three Months   Four Months   Five Months 
   Ended   Ended   Ended 
   September 30, 2018   September 30, 2018   May 31, 2018 
Gain on settlement of liabilities subject to compromise  $-   $-   $128,700 
Fresh start valuation adjustments   -    -    (700,325)
Professional fees   (972)   (1,780)   (13,345)
Other   -    -    (2,355)
Reorganization items, net  $(972)  $(1,780  $(587,325)

 

NOTE 4. REVENUE

 

On January 1, 2018, the Partnership adopted ASU No. 2014–09, Revenue from Contracts with Customers (“Topic 606”), using the modified retrospective method applied to contracts that were not completed as of January 1, 2018. Accordingly, the comparative information for the three and nine months ended September 30, 2017, has not been adjusted and continues to be reported under the previous revenue standard. The adoption of this ASU did not have a material impact on the unaudited condensed consolidated financial statements, and the primary impacts of this change in accounting policy for revenue recognition effective January 1, 2018, are detailed below.

 

There were no significant changes to the timing of revenue recognized for sales of production. However, as a result of management’s evaluation under new considerations within Topic 606, the adoption did result in certain contracts being recorded on a net basis instead of a gross basis, as well as some contracts being recorded on a gross basis instead of a net basis, as a result of the determined delivery point. These presentation changes did not have an impact on income or loss from operations, earnings per share/unit or cash flows, but did increase oil, natural gas and natural gas liquids revenues and lease operating expenses in the unaudited condensed consolidated financial statements by approximately $1.6 million and $2.0 million for the three and four months ended September 30, 2018 and by approximately $2.1 million for the five months ended May 31, 2018, respectively, as compared to what would have been recognized using the revenue recognition guidance that was in effect before the adoption of Topic 606.

 

The following table summarizes the impact of adopting Topic 606 on the unaudited condensed consolidated financial statements:

 

   Without   Impact of     
   Adoption of   Change in     
   Topic 606   Accounting Policy   As Reported 
Successor               
For the Three Months Ended September 30, 2018:               
Oil, natural gas and natural gas liquids revenues  $66,843   $1,564   $68,407 
Lease operating expenses  $26,717   $1,564   $28,281 
                
For the Four Months Ended September 30, 2018:               
Oil, natural gas and natural gas liquids revenues  $87,929   $2,013   $89,942 
Lease operating expenses  $35,643   $2,013   $37,656 
                
                
Predecessor               
For the Five Months Ended May 31, 2018:               
Oil, natural gas and natural gas liquids revenues  $108,253   $2,054   $110,307 
Lease operating expenses  $43,318   $2,054   $45,372 

 

Revenue from contracts with customers includes the sale of oil, natural gas and natural gas liquids production (recorded in “Oil, natural gas and natural gas liquids revenues” in the unaudited condensed consolidated statements of operations) and gathering and transportation revenues (recorded in “Transportation and marketing-related revenues” in the unaudited condensed consolidated statements of operations).

 

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Oil, Natural Gas and Natural Gas Liquids Revenues

 

Oil, natural gas and natural gas liquids revenues are recognized upon the transfer of control of the products to a purchaser. Transfer of control typically occurs when the products are delivered to the purchaser, title has transferred and collectability of the revenue is reasonably assured. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration the Company expects to receive in exchange for those products.

 

The Company’s oil production is primarily sold under market-sensitive contracts that are typically priced at a differential to the New York Mercantile Exchange (“NYMEX”) price or at purchaser posted prices for the producing area. For oil contracts, the Company generally records sales based on the net amount received.

 

The Company’s natural gas production is primarily sold under market-sensitive contracts that are typically priced at a differential to the published natural gas index price for the producing area due to the natural gas quality and the proximity to major consuming markets. For natural gas contracts, the Company generally records wet gas sales at the wellhead or inlet of the gas processing plant as revenues net of transportation, gathering and processing expenses if the processor is the customer and there is no redelivery of commodities to the Company at the tailgate of the plant. Conversely, the Company generally records residual natural gas and NGL sales at the tailgate of the plant on a gross basis along with the associated transportation, gathering and processing expenses if the processor is a service provider and there is redelivery of commodities to the Company at the tailgate of the plant. All facts and circumstances of an arrangement are considered and judgment is often required in making this determination.

 

In addition, the Company recognizes processing expenses for commodities paid as noncash consideration in exchange for processing services and recognizes the associated revenues for those same commodities. This recognition results in an increase to revenues and expenses with no impact on net income.

 

Harvest follows the sales method of accounting for natural gas revenues. Under this method of accounting, revenues are recognized based on volumes sold, which may differ from the volume to which the Company is entitled based on its working interest. An imbalance is recognized as a liability only when the estimated remaining reserves will not be sufficient to enable the under–produced owner(s) to recoup its entitled share through future production. Under the sales method, no receivables are recorded where the Company has taken less than its share of production.

 

Transportation and Marketing-Related Revenues

 

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

 

The following table disaggregates revenue by significant product and service type:

 

   Successor   Predecessor 
   Three Months   Four Months   Five Months 
   Ended   Ended   Ended 
   September 30, 2018   September 30, 2018   May 31, 2018 
Oil  $23,254   $30,415   $42,460 
Natural gas (1)   26,494    35,158    40,951 
Natural gas liquids (1)   18,659    24,369    26,896 
Oil, natural gas and natural gas liquids revenues   68,407    89,942    110,307 
Transportation and marketing–related revenues   559    744    724 
Total revenues  $68,966   $90,686   $111,031 

 

 

(1)The Company recognizes wet gas revenues, which are recorded net of transportation, gathering and processing expenses, partially as natural gas revenues and partially as natural gas liquids revenues based on the end products after processing occurs. For the Successor period of the three months ended September 30, 2018, wet gas revenues were $5.9 million which were recognized as $2.0 million of natural gas revenues and $3.9 million of natural gas liquids revenues. For the Successor period of the four months ended September 30, 2018, wet gas revenues were $7.4 million which were recognized as $2.5 million of natural gas revenues and $4.9 million of natural gas liquids revenues. For the Predecessor period of the five months ended May 31, 2018, wet gas revenues were $8.4 million which were recognized as $3.2 million of natural gas revenues and $5.2 million of natural gas liquids revenues.

 

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Contract Balances

 

Customers are invoiced once the Company’s performance obligations have been satisfied. Payment terms and conditions vary by contract type, although terms generally include a requirement of payment within 30 days. There are no significant judgments that significantly affect the amount or timing of revenue from contracts with customers. Accordingly, the Company’s product sales contacts do not give rise to material contract assets or contract liabilities. 

 

Accounts receivable are primarily from purchasers of oil, natural gas and natural gas liquids and from exploration and production companies that own interests in properties Harvest operates. This industry concentration could affect overall exposure to credit risk, either positively or negatively, because the Company’s purchasers and joint working interest owners may be similarly affected by changes in economic, industry or other conditions. The Company routinely assesses the financial strength of its customers and bad debts are recorded based on an account-by-account review specifically identifying receivables that the Company believes may be uncollectible after all means of collection have been exhausted, and the potential recovery is considered remote. As of September 30, 2018 and December 31, 2017, the Company did not have any reserves for doubtful accounts.

 

Performance Obligations

 

The Company applies the optional exemptions in Topic 606 and does not disclose consideration for remaining performance obligations with an original expected duration of one year or less or for variable consideration related to unsatisfied performance obligations.

 

NOTE 5. SHARE–BASED COMPENSATION

 

On the Effective Date, in connection with the Plan, the Company adopted the MIP, pursuant to which employees, directors, consultants and other service providers of the Company and its subsidiaries are eligible to receive stock options, stock appreciation rights, restricted stock, restricted stock units, other stock-based awards and cash-based awards. An aggregate of 689,362 shares of the Company’s common stock are reserved for issuance under the MIP. To the extent that an award under the MIP is expired, forfeited or cancelled for any reason without having been exercised in full, the unexercised award would then be available again for grant under the MIP.

 

The Compensation Committee of the Company’s Board of Directors (the “Board”) (or any properly delegated subcommittee thereof) or a committee of at least two people as the Board may appoint or, if no such committee or subcommittee has been appointed by the Board, the Board (the “Committee”) will administer the MIP. The Committee has broad authority under the MIP to, among other things: (i) select participants; (ii) determine the types of awards that participants are to receive and the number of shares or the amount of cash that are to be subject to such awards and grant such awards; and (iii) determine the terms, conditions and restrictions of awards, including the applicable performance criteria relating to the award.

 

During the four months ended September 30, 2018, the Company granted 54,800 shares of restricted stock under the MIP, which vested during September 2018 as a result of the closing of the Central Texas divestiture (defined in Note 6). See Note 6 for additional information about the divestiture. The weighted average fair value of the restricted shares granted during the four months ended September 30, 2018, was $19.99 with a total fair value of approximately $1.1 million. None of these shares were forfeited during the three or four months ended September 30, 2018. Approximately 0.6 million shares remain available for grant under the MIP as of September 30, 2018.

 

The Company recognized compensation cost related to these restricted shares of the full grant date fair value of $1.1 million for both the three and four months ended September 30, 2018 as the awards vested in September 2018. These costs are included in “General and administrative expenses” in the unaudited condensed consolidated statements of operations.

 

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Series A Preferred Stock

 

In connection with the Restructuring and in reliance on the exemption from the registration requirements of the Securities Act provided by Section 1145 of the Bankruptcy Code, Harvest issued 21,000 shares of Series A Preferred Stock to one employee of the Company and one employee of EnerVest for consideration of services to the Company pursuant to Preferred Stock Purchase Agreements, dated as of the Effective Date, which vest on the earlier of (i) June 4, 2019 or (ii) immediately prior to the consummation of a Sale Transaction (as defined in the Certificate of Designations). The Company estimated the fair value of the Series A Preferred Stock as of September 30, 2018 at $0.2 million. The fair value of the preferred stock award will be recognized on a straight–line basis over the service period, and the Company will account for forfeitures as they occur. During both the three and four months ended September 30, 2018, the Company recognized $49 thousand of compensation cost related to this preferred stock. These costs are included in “General and administrative expenses” in the unaudited condensed consolidated statement of operations.

 

Each holder of the Series A Preferred Stock is entitled to receive mandatory and cumulative dividends payable semi-annually in arrears with respect to each dividend period ending on and including the last calendar day of each six-month period ending June 4 and December 4, at a rate per share of Series A Preferred Stock equal to 8.0% per annum payable upon the Liquidation Preference (as defined in the Certificate of Designations) payable in kind unless another form of payment is designated by the Board of Directors of the Company. In the event that dividends due to each share of Series A Preferred Stock have not been paid for a period of two consecutive Dividend Periods (as defined in the Certificate of Designations), the holders of the Series A Preferred Stock, as an independent class, shall be entitled to nominate and vote to appoint one director of the Board of Directors of the Company. Holders of shares of Series A Preferred Stock have no right, by virtue of their status as holders of shares of Series A Preferred Stock, to vote on any matters on which holders of shares of New Common Stock are entitled to vote.

 

The Series A Preferred Stock shall automatically be redeemed upon the consummation of a Sale Transaction (as defined in the Certificate of Designation) at a price equal to the Accrued Liquidation Preference (as defined in the Certificate of Designation). The Series A Preferred Stock may be redeemed at the option of the Company after June 4, 2023, in whole or in part, at a price equal to the Accrued Liquidation Preference. The Series A Preferred Stock may be redeemed at the option of the holder after June 4, 2039, in whole or in part, at a price equal to the Accrued Liquidation Preference.

 

Predecessor Equity-Based Compensation

 

EV Management had two long-term incentive plans, the 2006 Long-Term Incentive Plan (the “2006 Plan”) and the 2016 Long-Term Incentive Plan (the “2016 Plan” and together, the “Plans”) for employees, consultants and directors of EV Management and its affiliates who performed services for EVEP. These equity–based awards consisted only of phantom units as of May 31, 2018.

 

EVEP estimated the fair value of the phantom units at the grant date using the Black–Scholes option pricing model. These phantom units were subject to graded vesting over a four year period. Compensation cost had been recognized for these phantom units on a straight–line basis over the service period, and EVEP accounted for forfeitures as they occurred.

 

The Predecessor recognized compensation cost related to these phantom units of $1.0 million for the five months ended May 31, 2018, under the normal vesting schedule. The Predecessor recognized compensation cost related to these phantom units of $1.1 million and $3.3 million in the three months and nine months ended September 30, 2017, respectively. These costs are included in “General and administrative expenses” in the unaudited condensed consolidated statements of operations.

 

On June 4, 2018, EVEP’s emergence from bankruptcy, which constituted a change of control, resulted in the immediate acceleration of all unvested phantom units. As a result, the total unrecognized compensation cost of $2.8 million was recognized as of May 31, 2018. These costs are included in “General and administrative expenses” in the unaudited condensed consolidated statements of operations.

 

Activity related to these phantom units is as follows:

 

   Number   Weighted Average 
   of   Grant Date 
   Phantom Units   Fair Value 
Nonvested phantom units as of December 31, 2017 (Predecessor)   1,511,920   $4.54 
Granted   -    - 
Vested   (1,460,234)   4.58 
Forfeited   (51,686)   3.42 
Nonvested phantom units as of May 31, 2018 (Predecessor)   -   $- 

 

The total grant date fair value of the phantom units vested in 2018 was $6.7 million.

 

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NOTE 6. DIVESTITURES

 

On August 31, 2018, the Company closed the sale of certain oil and gas properties in Central Texas and Karnes County, Texas (the “Central Texas Divestiture”) to Magnolia Oil & Gas Parent LLC and Magnolia Oil & Gas Corporation (collectively, “Magnolia”) for total consideration of $133.3 million in cash, net of preliminary purchase price adjustments, and 4.2 million shares of common stock of Magnolia (NYSE: MGY). Based on the closing price for Magnolia’s common stock on August 31, 2018, total consideration was $191.5 million, net of preliminary purchase price adjustments.

  

In addition, in August 2018, the Company closed the sale of certain oil and gas properties in Central Texas to a third party for $3.5 million, net of preliminary purchase price adjustments.

 

NOTE 7. RISK MANAGEMENT 

 

The Company’s business activities expose it to risks associated with changes in the market price of oil, natural gas and natural gas liquids. In addition, the Company’s floating rate credit facility exposes it 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. The Company uses derivatives to reduce its risk of volatility in the prices of oil, natural gas and natural gas liquids and interest rates. The Company policies do not permit the use of derivatives for speculative purposes.

 

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

 

In April 2018, in conjunction with the Chapter 11 proceedings, the Predecessor terminated its interest rate swaps for the period of April 2018 to September 2020, which resulted in a cash settlement received in April 2018 of $1.6 million.

 

After the Effective Date, the Company entered into new commodity derivative contracts. As of September 30, 2018, the Company had entered into the following terms:

 

       Weighted 
       Average 
   Hedged   Fixed 
Period Covered  Volume   Price 
Oil (MBbls):          
Swaps – October 2018 to December 2018   276.0   $66.34 
Swaps – January 2019 to December 2019   1,022.0   $63.02 
Swaps – January 2020 to December 2020   732.0   $60.51 
           
Natural Gas (MMBtus):          
Swaps – October 2018 to December 2018   8,280.0   $2.91 
Swaps – January 2019 to December 2019   31,025.0   $2.77 
           
Natural Gas Liquids (MBbls):          
Swaps – October 2018 to December 2018   276.0   $20.82 
Swaps – January 2019 to December 2019   1,095.0   $18.58 
Swaps – January 2020 to December 2020   768.6   $17.68 

 

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 The following table sets forth the fair values and classification of the Company’s outstanding derivatives:

 

   Successor 
           Net Amounts 
       Gross Amounts   of Assets 
       Offset in the   Presented in the 
   Gross   Unaudited   Unaudited 
   Amounts of   Condensed   Condensed 
   Recognized   Consolidated   Consolidated 
   Assets   Balance Sheet   Balance Sheet 
As of September 30, 2018:               
Derivative asset  $8   $(8)  $- 
Long-term derivative asset   124    (124)   - 
Total  $132   $(132)  $- 
                
Derivative liability  $18,321   $(8)  $18,313 
Long-term derivative liability   10,619    (124)   10,495 
Total  $28,940   $(132)  $28,808 

 

   Predecessor 
           Net Amounts 
       Gross Amounts   of Liabilities 
       Offset in the   Presented in the 
   Gross   Unaudited   Unaudited 
   Amounts of   Condensed   Condensed 
   Recognized   Consolidated   Consolidated 
   Liabilities   Balance Sheet   Balance Sheet 
As of December 31, 2017:               
Derivative asset  $3,402   $(350)  $3,052 
                
Derivative liability  $746   $(350)  $396 

 

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

 

NOTE 8. 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 the Company’s own assumptions used to measure assets and liabilities at fair value.

 

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Recurring Basis

 

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

 

   Successor 
       Fair Value Measurements
at the End of the Reporting Period
 
       Quoted         
       Prices         
       in Active   Significant     
       Markets for   Other   Significant 
       Identical   Observable   Unobservable 
       Assets   Inputs   Inputs 
   Fair Value   (Level 1)   (Level 2)   (Level 3) 
As of September 30, 2018:                    
Assets:                    
Oil, natural gas and natural gas liquids derivatives  $132   $-   $132   $- 
Equity securities   63,042    -    63,042    - 
   $63,174   $-   $63,174   $- 
                     
Liabilities:                    
Oil, natural gas and natural gas liquids derivatives  $28,940   $-   $28,940   $- 

 

   Predecessor 
       Fair Value Measurements
at the End of the Reporting Period
 
       Quoted         
       Prices         
       in Active   Significant     
       Markets for   Other   Significant 
       Identical   Observable   Unobservable 
       Assets   Inputs   Inputs 
   Fair Value   (Level 1)   (Level 2)   (Level 3) 
As of December 31, 2017:                    
Assets:                    
Oil, natural gas and natural gas liquids derivatives  $2,696   $-   $2,696   $- 
Interest rate swaps   706    -    706    - 
   $3,402   $-   $3,402   $- 
                     
Liabilities:                    
Oil, natural gas and natural gas liquids derivatives  $721   $-   $721   $- 
Interest rate swaps   25    -    25    - 
   $746   $-   $746   $- 

 

The Company’s 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, the Company has categorized these derivatives as Level 2. The Company values 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. Estimates of fair value have been determined at discrete points in time based on relevant market data. Furthermore, fair values are adjusted to reflect the credit risk inherent in the transaction, which may include amounts to reflect counterparty credit quality and/or the effect of the Company’s creditworthiness. These assumed credit risk adjustments are based on published credit ratings, public bond yield spreads and credit default swap spreads. There were no changes in valuation techniques or related inputs in the nine months ended September 30, 2018. 

 

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The Company’s equity securities consist of 4.2 million shares of common stock of Magnolia which are traded on a public exchange. While the fair value of these shares is based market price, the Company has categorized these equity securities as Level 2, as the Company is subject to a 120 day lock-up after August 31, 2018, regarding the sale of these shares.

 

Nonrecurring Basis

 

During the three and four months ended September 30, 2018, the Company recognized an impairment expense of $2.6 million related to proved oil and natural gas properties in Central Texas and Karnes County, Texas which were sold during August 2018. During the five months ended May 31, 2018, the Predecessor did not recognize any impairment expense related to proved oil and natural gas properties. During the three months ended September 30, 2017, the Predecessor did not recognize any impairment expense related to proved oil and natural gas properties. During the nine months ended September 30, 2017, the Predecessor recognized $67.7 million of impairment expense related to proved oil and natural gas properties; $49.5 million of this impairment related to properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to properties located in the Monroe Field and $2.9 million related to properties in East Texas which were sold during April 2017.

 

The fair values were determined using the income approach and were based on the expected present value of the future net cash flows from reserves. Significant Level 3 assumptions associated with the calculation of discounted cash flows used in the impairment analysis included estimates of future prices, production costs, development expenditures, anticipated production of the Company’s estimated reserves, appropriate risk–adjusted discount rates and other relevant data.

 

Financial Instruments 

 

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

 

The carrying value of debt outstanding under the Exit Credit Facility approximates fair value because the credit facility’s variable interest rate resets frequently and approximates current market rates available to the Company. The estimated fair value of the Predecessor’s Senior Notes was $176.8 million at December 31, 2017, which differs from the carrying value of $342.5 million at December 31, 2017. The fair value of the Senior Notes was determined using Level 2 inputs.

 

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NOTE 9. ASSET RETIREMENT OBLIGATIONS 

 

The Company records an asset retirement obligation (“ARO”) and capitalizes 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: 

 

ARO as of December 31, 2017 (Predecessor)  $161,963 
Liabilities incurred   77 
Accretion expense   3,176 
Settlements and divestitures   (385)
ARO as of May 31,2018 (Predecessor)   164,831 
Fresh start adjustments (1)   (41,953)
ARO as of May 31, 2018 (Successor)   122,878 
Liabilities incurred   6 
Accretion expense   3,134 
Settlements and divestitures   (7,533)
ARO as of September 30, 2018 (Successor)  $118,485 

 

 

(1)As a result of the application of fresh start accounting, the Successor recorded its asset retirement obligations at fair value as of the Effective Date.

 

As of September 30, 2018, $2.7 million of the Successor ARO and as of December 31, 2017, $3.2 million of the Predecessor ARO is classified as current and is included in “Accounts payable and accrued liabilities” in the unaudited condensed consolidated balance sheets, respectively.

 

NOTE 10. LONG–TERM DEBT 

 

The following table presents the consolidated debt obligations at the dates indicated:

 

   Successor   Predecessor 
   September 30, 2018   December 31, 2017 
Successor Exit Credit Facility  $133,000   $- 
Predecessor Credit facility   -    263,000 
Predecessor 8.0% senior notes due April 2019:          
Principal outstanding   -    343,348 
Unamortized discount and debt issuance costs (1)   -    (1,701)
Unaccreted premium (2)   -    902 
    -    342,549 
Total debt   133,000    605,549 
Less: Current portion of long-term debt (3)   -    (605,549)
Long-term debt, net  $133,000   $- 

 

 

(1)Imputed interest rate of 8.49% for December 31, 2017.

 

(2)Imputed interest rate of 7.43% for December 31, 2017.

 

(3)Due to the anticipated financial covenant violations as of December 31, 2017, the borrowings under the Predecessor’s credit facility and Senior Notes were classified as current at December 31, 2017. There were no existing or anticipated financial covenant violations as of September 30, 2018.

 

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Exit Credit Facility 

 

In connection with the Company’s emergence from bankruptcy, on the Effective Date, the Company entered into a Credit Agreement providing for a $1.0 billion new reserve-based revolving loan. The Exit Credit Facility matures on February 26, 2021. Borrowings under the Exit Credit Facility are secured by a first priority lien on substantially all of the Company’s oil and natural gas properties. The Company may use borrowings under the Exit Credit Facility for acquiring and developing oil and natural gas properties, for working capital purposes and for general corporate purposes. The Company also may use up to $50.0 million of available borrowing capacity for letters of credit. As of September 30, 2018, the Company had a $0.2 million letter of credit outstanding.

 

The terms of the credit facility do not require any repayments of amounts outstanding until it matures in February 2021. Borrowings under the credit facility bear interest at a floating rate based on, at the Company’s election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base outstanding (weighted average effective interest rate of 5.25% at September 30, 2018). 

 

Borrowings under the Exit Credit Facility may not exceed a “borrowing base” determined by the lenders under the credit facility based on the Company’s oil and natural gas reserves. In August 2018, as a result of the Central Texas divestiture, the borrowing base was reduced by $60.3 million to $264.7 million. As of September 30, 2018, the borrowing base under the Exit Credit Facility was $264.7 million. The borrowing base is subject to scheduled redeterminations starting on April 1, 2019, and semi-annually as of April 1 and October 1 of each year thereafter with an additional redetermination once per calendar year at the election of either the Company or the lenders.

 

The Exit Credit Facility requires the maintenance of the following (as defined in the Credit Agreement):

 

·the Total Debt to EBITDAX ratio covenant to be no greater than 4.0 to 1.0;

 

·the current consolidated assets (including unused commitments under the Exit Credit Facility) to current consolidated liabilities to be no less than 1.0 to 1.0;

 

·requires the percentage of Mortgaged Properties to be no less than 95% of the total value of the Oil and Gas Properties evaluated in the most recent Reserve Report;

 

·required that, no later than 60 days following the Effective Date, 70% of projected production volumes (excluding projected production volumes from certain properties) be hedged (as of the date such swap agreements were executed) for the 18 months following the Effective Date; and

 

·limits cash held by the Company to the greater of 5% of the current borrowing base or $30.0 million.

 

As of September 30, 2018, the Company was in compliance with all of these financial covenants.

 

Predecessor’s Credit Facility 

 

The Predecessor was party to a $1.0 billion credit facility, which was scheduled to expire in February 2020. Borrowings under that credit facility were secured by a first priority lien on substantially all of the Predecessor’s oil and natural gas properties. The Predecessor also had access to up to $100.0 million of available borrowing capacity for letters of credit. As of May 31, 2018, the Predecessor had a $0.2 million letter of credit outstanding.

 

The terms of the Predecessor’s credit facility did not require any repayments of amounts outstanding until it expired in February 2020. Borrowings under the credit facility bore interest at a floating rate based on, at the Partnership’s election, a base rate or the London Inter–Bank Offered Rate plus applicable premiums based on the percent of the borrowing base that the Partnership had outstanding (weighted average effective interest rate of 5.47% and 4.82% at May 31, 2018 and December 31, 2017, respectively). 

 

Borrowings under the Predecessor’s credit facility could not exceed a “borrowing base” determined by the lenders under the credit facility based on the Company’s oil and natural gas reserves. As of May 31, 2018, the borrowing base under the Predecessor’s credit facility was $325.0 million.

 

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In connection with EVEP’s emergence from bankruptcy on June 4, 2018, the holders of claims under the Predecessor’s credit facility received full recovery, consisting of (i) their pro rata share of the $1 billion new reserve-based revolving loan; (ii) cash in amount equal to the accrued but unpaid interest payable to such lenders under the credit facility as of the Effective Date; and (iii) unfunded commitments and letter of credit participation under the Exit Credit Facility equal to the unfunded commitments and letter of credit participation of such lender as of the Effective Date.

 

Predecessor’s 8.0% Senior Notes due April 2019 

 

The Predecessor’s Senior Notes were issued under the Indenture, would have matured April 15, 2019 and bore interest at 8.0%. The Senior Notes were fully and unconditionally guaranteed, jointly and severally, on a senior unsecured basis, by all of the Predecessor’s wholly owned subsidiaries other than EV Energy Finance Corp. (“Finance”), which was a co–issuer of the Senior Notes. Neither EVEP nor Finance had independent assets or operations apart from the assets and operations of the Predecessor’s subsidiaries.

 

As a result EVEP’s emergence from bankruptcy, the Senior Notes were cancelled and the Predecessor’s liability thereunder discharged as of June 4, 2018, and the holders of the Notes received (directly or indirectly) their pro rata share of New Common Stock representing, in the aggregate, 95% of the New Common Stock on the Effective Date (subject to dilution by the MIP and the common shares issuable upon exercise of the Warrants). See also Note 2.

 

NOTE 11. COMMITMENTS AND CONTINGENCIES

 

On the Effective Date, Harvest entered into a Services Agreement (the “Services Agreement”) with EnerVest, Ltd. and EnerVest Operating, L.L.C. (together, the “EnerVest Group”). Pursuant to the Services Agreement, the EnerVest Group will provide certain administrative, management, operating and other services and support to Harvest (the “Services”) following the Effective Date. In addition, the EnerVest Group will also provide Harvest with sufficient office space, equipment and office supplies pursuant to the Services Agreement. The Services Agreement covers the people EnerVest employs who provide direct support to the Company’s operations; however, the Services Agreement does not cover the six full-time employees of Harvest which include the Chief Executive Officer and the Chief Financial Officer. The management fee is subject to an annual redetermination by agreement of the parties and may also be adjusted for acquisitions or divestitures over $5 million. Prior to the Central Texas divestiture, Harvest paid the EnerVest Group a management fee equal to $1,433,333 per month. As a result of the Central Texas divestiture, the fee was reduced by $288,375 per month. Starting in September 2018, Harvest will pay to the EnerVest Group a management fee equal to $1,144,958 per month. The EnerVest Group will provide the Services until December 31, 2020.

 

The Company is involved in disputes or legal actions arising in the ordinary course of business. The Company does not believe the outcome of such disputes or legal actions, other than addressed below, will have a material effect on its unaudited condensed consolidated financial statements. No amounts were accrued at September 30, 2018 or December 31, 2017.

 

In August 2018, the Company was notified by the Office of Natural Resources Revenue (“ONRR”) of potential underpayments of royalties related to certain leases for the period of 2009 through 2018. The Company also received an extension from ONRR to amend the royalty filings which expires in December 2018. Any potential liability for underpayment is currently not estimable, but could be material to the unaudited condensed consolidated financial statements. No amount has been accrued as of September 30, 2018.

 

NOTE 12. INCOME TAXES

 

Effective June 4, 2018, pursuant to the Plan, the Successor became a corporation subject to federal and state income taxes. Prior to the Plan being effective, the Predecessor was a limited partnership and organized as a pass-through entity for federal and most state income tax purposes. As a result, the Predecessor’s limited partners were responsible for federal and state income taxes on their share of taxable income. The Predecessor was subject to the Texas margin tax for partnership activity in the state of Texas. The Successor is also subject to the Texas margin tax for corporate activity in the state of Texas after the Effective Date of the Plan. Obligations of the Predecessor and Successor under the Texas gross margin tax are recorded as “Income taxes” in the unaudited condensed consolidated statements of operations.

 

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Management assesses the available positive and negative evidence to estimate whether it is more likely than not that sufficient future taxable income will be generated to realize the Company’s deferred tax assets. Due to significant negative evidence, the Company has established a valuation allowance against its net deferred tax asset of $22.9 million as of September 30, 2018.  In addition to the emergence from bankruptcy, the Predecessor incurred a cumulative loss over the three-year period ended June 4, 2018. The net deferred tax asset before valuation allowance as of September 30, 2018 primarily relates to temporary differences in GAAP and tax bankruptcy emergence valuations.

 

The Company had no income tax expense or benefit for the period from June 1, 2018 through September 30, 2018 as a result of changes in valuation allowances. The Company recorded an income tax expense for the period from January 1, 2018 through May 31, 2018 of $0.2 million related to state income taxes. The Company’s income tax benefit related to state income taxes for the nine months ended September 30, 2017 was $0.1 million.

 

NOTE 13. EQUITY 

 

Issuance of Common Stock and Cancellation of Units

 

In accordance with the Plan, on the Effective Date:

 

·the Company issued a total of 10,000,016 shares of its common stock, which included the issuance of (i) 9,500,000 shares pro rata to holders of the Senior Notes with claims allowed under the Plan and (ii) 500,016 shares pro rata to holders of units of EVEP prior to the Effective Date;

 

·the Company issued 800,000 warrants to purchase 800,000 shares of the Company’s common stock to holders of units of EVEP prior to the Effective Date;

 

·the Predecessor common units were cancelled; and

 

·each Predecessor common unitholder received its pro rata share of: (i) 5% of the New Common Stock and (ii) the Warrants as discussed above.

 

On the Effective Date, there were 10,000,016 shares of New Common Stock issued and outstanding. As of September 30, 2018, there were 10,054,816 shares issued and 10,042,468 shares outstanding.

 

Warrants

 

On the Effective Date, the Company entered into a warrant agreement with Computershare Trust Company N.A., as warrant agent, pursuant to which the Company issued Warrants to purchase up to 800,000 shares of the Company’s common stock (representing 8% of the Company’s outstanding total issued and outstanding common stock as of the Effective Date including shares of the Company’s common stock issuable upon full exercise of the Warrants, but excluding any common stock issuable under the MIP), exercisable for a five year period commencing on the Effective Date at an exercise price of $37.48 per warrant.

 

The fair values for the Warrants upon issuance have been estimated using the Black-Scholes option pricing model using the following assumptions:

 

   Warrants Issued in
Successor Period
 
Risk–free interest rate   2.8%
Dividend yield   0.0%
Expected life (years)   5.0 
Expected volatility   69.0%
Strike price  $37.48 
Calculated fair value  $9,345 

 

Predecessor

 

At May 31, 2018, owners’ equity consisted of 49,368,869 common units, representing a 98% limited partnership interest in us, and a 2% general partnership interest. During the five months ended May 31, 2018, the Predecessor did not issue any common units.

 

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Net income of the Predecessor was allocated between the general partner and the limited partners in accordance with the provisions of the partnership agreement. Net income was generally allocated first to the general partner and the limited partners in an amount equal to the net losses allocated to the general partner and the limited partners in the current and prior tax years under the partnership agreement. The remaining net income was allocated to the general partner and the limited partners in accordance with their respective percentage interests of the general partner and limited partners.

 

Predecessor Cash Distributions 

 

The Predecessor’s credit facility prohibited the Partnership from making cash distributions if any default or event of default, as defined in the credit facility, occurred or would result from the cash distribution.

 

Within 45 days after the end of each quarter, the Predecessor would distribute all of its available cash (as defined in the partnership agreement) to its general partner and unitholders of record on the applicable record date. The amount of available cash generally was all cash on hand at the end of the quarter; less the amount of cash reserves established by the general partner to provide for the proper conduct of business, to comply with applicable laws, any of the debt instruments, or other agreements or to provide funds for distributions to unitholders and to the general partner for any one or more of the next four quarters; plus all cash on hand on the date of determination of available cash for the quarter resulting from working capital borrowings made after the end of the quarter. Working capital borrowings were generally borrowings that are made under the credit facility and in all cases was used solely for working capital purposes or to pay distributions to partners.

 

The partnership agreement required that the Predecessor make distributions of available cash from operating surplus in the following manner:

 

·first, 98% to the unitholders, pro rata, and 2% to the general partner, until the Predecessor distributed for each outstanding common unit an amount equal to the minimum quarterly distribution for that quarter; and

 

·thereafter, cash in excess of the minimum quarterly distributions was distributed to the unitholders and the general partner based on the percentages below.

 

The minimum quarterly distribution was not guaranteed and distributions below the minimum quarterly distribution would not be accrued in arrears.

 

The general partner was entitled to incentive distributions if the amount distributed with respect to one quarter exceeded specified target levels shown below:

 

      Marginal Percentage
Interest in Distributions
 
   Total Quarterly Distributions
Target Amount
  Limited
Partner
   General
Partner
 
Minimum quarterly distribution  $0.7615   98%   2%
First target distribution  Up to $0.875725   98%   2%
Second target distribution  Above $0.875725, up to $0.951875   85%   15%
Thereafter  Above $0.951875   75%   25%

 

During 2017, the board of directors of EV Management announced that it had elected to suspend distributions to unitholders for all four quarters of 2017. The board of directors also elected to suspend distributions for the first quarter of 2018.

 

NOTE 14. EARNINGS PER SHARE/UNIT 

 

Basic earnings (loss) per share/unit is computed by dividing net earnings attributable to stockholders/unitholders by the weighted average number of shares/units outstanding during the period. Diluted earnings per share/unit is computed by adjusting the average number of shares/units outstanding for the dilutive effect, if any, of potential common shares/units. The Company uses the treasury stock method to determine the dilutive effect.

 

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The Predecessor used the two–class method to compute earnings per limited partner unit. The two-class method is an earnings allocation formula that determines earnings per unit for common units and participating securities as if all earnings for the period had been distributed. As the Predecessor’s unvested phantom units and its earned but unvested performance units participated in dividends on an equal basis with the common units, they were considered to be participating securities. Earnings used in the determination of earnings per limited partner unit for each reporting period was reduced by the amount of earnings allocated to the general partner and available cash that would be distributed to the limited partners and the participating securities. The undistributed earnings, if any, were then allocated to the limited partners and the participating securities in accordance with the terms of the partnership agreement. Basic and diluted earnings per limited partner unit were then calculated by dividing earnings, after deducting the amount allocated to the general partner and the earnings attributable to the participating securities, by the weighted average number of outstanding limited partner units during the period.

 

The following sets forth the calculation of earnings per share/unit, for the period indicated:

 

   Successor   Predecessor 
   Three Months   Four Months   Three Months   Five Months   Nine Months 
   Ended   Ended   Ended   Ended   Ended 
   September 30,   September 30,   September 30,   May 31,   September 30, 
   2018   2018   2017   2018   2017 
Net loss attributable to Successor/Predecessor  $(9,760)  $(10,298)  $(17,888)  $(610,525)  $(93,880)
Predecessor's general partner’s 2% interest in net loss   -    -    358    12,211    1,878 
Earnings attributable to Predecessor's unvested phantom units   -    -    -    -    - 
Net loss available to common stockholders/limited partners  $(9,760)  $(10,298)  $(17,530)  $(598,314)  $(92,002)
                          
Weighted average common shares/units outstanding:                         
Basic   10,028    10,021    49,369    49,369    49,353 
Dilutive effect of potential common shares/units   -    -    -    -    - 
Diluted   10,028    10,021    49,369    49,369    49,353 
                          
Net earnings per share/unit:                         
Basic  $(0.97)  $(1.03)  $(0.36)  $(12.12)  $(1.86)
Diluted  $(0.97)  $(1.03)  $(0.36)  $(12.12)  $(1.86)
                          
Antidilutive warrants (1)   800,000    800,000    -    -    - 

 

 

(1)Amount represents warrants to purchase common stock that are excluded from the diluted net earnings per share calculations because of their antidilutive effect.

 

NOTE 15. RELATED PARTY TRANSACTIONS

 

As a result the Restructuring, EnerVest is no longer a related party to the Company. However, Harvest will continue to its relationship with EnerVest through an agreement for EnerVest to operate its properties. See Note 11 for additional information regarding the Services Agreement.

 

Prior to emergence from bankruptcy, the Predecessor’s general partner was EV Energy GP, and the general partner of its general partner was EV Management. EV Management is a wholly owned subsidiary of EnerVest. EnerVest and its affiliates also had a significant interest in the Partnership through their 71.25% ownership of EV Energy GP which, in turn, owned a 2% general partner interest in the Partnership and all of its incentive distribution rights. In addition, the Predecessor’s board of directors included directors who were also executives of EnerVest. As a result, EnerVest was considered a related party to the Predecessor.

 

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However, in accordance with the Plan, EV Energy GP, the Predecessor’s general partner, was dissolved following the Effective Date, and the terms of the Predecessor’s board of directors automatically expired on the Effective Date. The Successor formed a new five-member board of directors which does not consist of any members of EnerVest management. As a result, EnerVest is not considered a related party to the Successor.

 

Pursuant to a services agreement, referred to as an omnibus agreement, the Predecessor paid EnerVest $7.2 million for general and administrative services provided during the five months ended May 31, 2018. Under the omnibus agreement, the Predecessor also paid EnerVest $3.5 million and $10.5 million for services provided during the three and nine months ended September 30, 2017, respectively. These fees were based on an allocation of charges between EnerVest and EVEP based on the estimated use of such services by each party, and the Partnership believed that the allocation method employed by EnerVest was reasonable and reflective of the estimated level of costs the Partnership would have incurred on a standalone basis. These fees are included in “General and administrative expenses” in the unaudited condensed consolidated statements of operations.

 

The Partnership entered into operating agreements whereby a wholly owned subsidiary of EnerVest and its affiliates acted as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which EVEP owned an interest. The Predecessor reimbursed EnerVest approximately $8.4 million in the five months ended May 31, 2018, for direct expenses incurred in the operation of its wells and related gathering systems and production facilities and for the allocable share of the costs of EnerVest employees who performed services on its properties. Under that operating agreement, the Predecessor also reimbursed EnerVest $4.5 million and $14.0 million in the three and nine months ended September 30, 2017, respectively, for direct expenses incurred. As the vast majority of such expenses were charged to the Partnership on an actual basis (i.e., no mark–up or subsidy is charged or received by EnerVest), EVEP believed that the aforementioned services were provided at fair and reasonable rates relative to the prevailing market and were representative of the costs that would have been incurred on a standalone basis. These costs are included in “Lease operating expenses” in the unaudited condensed consolidated statements of operations. Additionally, in its role as contract operator, this EnerVest subsidiary also collected proceeds from oil and natural gas sales and distributed them to the Partnership and other working interest owners.

 

As of December 31, 2017, the Predecessor owed EnerVest Operating $4.2 million.

 

Effective November 1, 2011, EVEP, along with certain institutional partnerships managed by EnerVest, sold a portion of its unproved, undeveloped Utica acreage in ten Ohio counties to Total E&P USA, Inc. A portion of the purchase price was paid in cash with the balance payable in the form of a carried interest in future development activity. In early 2017, the allocated share of the Carry for one of the institutional partnerships was completely utilized. As such, that institutional partnership purchased Carry rights from EVEP and the other institutional partnerships equal to the benefit to be received from Total for their continued participation in the Carry. EVEP’s share of this benefit was $0.7 million for the five months ended May 31, 2018. These purchased Carry rights were recorded as reimbursements to oil and gas properties. During the four months ended September 30, 2018, the institutional partnership continues to purchase Carry rights from Harvest, however, the institutional partnership is no longer considered a related party.

 

NOTE 16. OTHER SUPPLEMENTAL INFORMATION

 

Supplemental cash flows and noncash transactions were as follows: 

 

   Successor   Predecessor 
   Four Months   Five Months   Nine Months 
   Ended   Ended   Ended 
   September 30, 2018   May 31, 2018   September 30, 2017 
Supplemental cash flows information:               
Cash paid for interest  $4,383   $6,008   $22,090 
Cash paid for reorganization items (1)   8,733    6,691    - 

 

 

(1)Includes approximately $6.9 million disbursed from the restricted cash account during the four months ended September 30, 2018.

 

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   Successor   Predecessor 
   September 30,
2018
   September 30,
2017
 
         
Non-cash transactions:          
Costs for additions to oil and natural gas properties          
in accounts payable and accrued liabilities  $4,232   $9,840 

 

Accounts payable and accrued liabilities consisted of the following:

 

   Successor   Predecessor 
   September 30,   December 31, 
   2018   2017 
Lease operating expenses  $11,041   $11,411 
Production and ad valorem taxes   4,969    6,351 
Costs for additions to oil and natural gas properties   4,232    12,748 
General and administrative expenses   2,881    3,331 
Current portion of ARO   2,716    3,170 
Derivative settlements   1,126    573 
Reorganization items   304    - 
Interest   58    5,820 
Other   344    413 
Total  $27,671   $43,817 

 

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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 related notes included in this Quarterly Report on Form 10-Q and the related notes thereto, as well as EVEP’s (as defined below) Annual Report on Form 10–K for the year ended December 31, 2017. 

 

OVERVIEW

 

Harvest Oil & Gas Corp. is a newly formed Delaware corporation and the successor reporting company to EV Energy Partners, L.P. (“EVEP”) pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). As used herein, the terms “Successor”, “Harvest”, the “Company”, “we”, “our” or “us” refer to Harvest Oil & Gas Corp. and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. When referring to the “Predecessor” or the “Partnership” in reference to the period prior to the emergence from bankruptcy, the intent is to refer to EVEP, the predecessor that was dissolved following the Effective Date (as defined below) of the Plan (as defined below) and its consolidated subsidiaries as a whole or on an individual basis, depending on the context in which the statements are made. Unless the context requires otherwise, references to: (i) the “Predecessor’s general partner” and “EV Energy GP” refer to EV Energy GP, L.P., a Delaware limited partnership, the Predecessor’s general partner, which was dissolved following the Effective Date of the Plan; (ii) “EV Management” refers to EV Management, LLC, a Delaware limited liability company, the former general partner of the Predecessor’s general partner; and (iii) “EnerVest” refers to EnerVest, Ltd., a Texas limited partnership, the owner of EV Management.

 

Harvest is an independent oil and natural gas company that was formed in June 2018, in connection with the reorganization of the Predecessor. The Predecessor was publicly traded from September 2006 to June 2018. On April 2, 2018, EV Energy Partners, L.P., and 13 affiliated debtors (collectively, the “Debtors”) each filed the Chapter 11 proceedings for relief under Chapter 11 for bankruptcy protection in the United States Bankruptcy Court for the District of Delaware (the “Bankruptcy Court”) via Case No. 18-10814. The Debtors requested that their cases be jointly administered under Case No. 18-10814. During the pendency of the Chapter 11 proceedings, EVEP continued to operate its businesses and manage its properties under the jurisdiction of the Bankruptcy Court and in accordance with the applicable provisions of the Bankruptcy Code and orders of the Bankruptcy Court as a “Debtors-in-Possession”. On May 17, 2018, the Bankruptcy Court entered an order (the “Confirmation Order”) confirming the Debtors’ First Modified Joint Prepackaged Plan of Reorganization (as amended, modified and supplemented from time to time, the “Plan”). The Plan became effective on June 4, 2018 (the “Effective Date”), when all remaining conditions to the effectiveness of the Plan were satisfied and the Company emerged from bankruptcy. See Note 2 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

We operate one reportable segment engaged in the development and production of oil and natural gas properties, and all of our operations are located in the United States. From time to time, we may look to divest assets and use proceeds to repay bank debt, concentrate in existing positions or venture into new basins. Our oil and natural gas properties are located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin and the Monroe Field in Northern Louisiana. As of December 31, 2017, we had estimated net proved reserves of 13.4 MMBbls of oil, 543.7 Bcf of natural gas and 31.6 MMBbls of natural gas liquids, or 813.6 Bcfe.

 

Emergence from Voluntary Reorganization under Chapter 11

 

On March 13, 2018, the Debtors entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with (i) holders of approximately 70% of the 8.0% senior unsecured notes due April 2019; (ii) lenders under the Predecessor’s reserve-based lending facility, initially constituting approximately 94%, but subsequently increased to 100%, of the principal amount outstanding thereunder; (iii) EnerVest; and (iv) EnerVest Operating, L.L.C. The Restructuring Support Agreement set forth, subject to certain conditions, the commitment of the Debtors and the consenting creditors to support a comprehensive restructuring of the Debtors’ long-term debt (the “Restructuring”).

 

On April 2, 2018 (the “Petition Date”), the Debtors each filed Chapter 11 proceedings under Chapter 11 in the Bankruptcy Court. The Debtors’ Chapter 11 proceedings were jointly administered under the caption In re EV Energy Partners, L.P., et al., Case No. 18-10814.

 

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On May 17, 2018, the Bankruptcy Court entered the Confirmation Order confirming the Debtors’ Plan.

 

On June 4, 2018, the Debtors satisfied the conditions to effectiveness of the Plan, the Plan became effective in accordance with its terms and the Company emerged from bankruptcy. Although the Company is no longer a debtor-in-possession, the Company was a debtor-in-possession through June 4, 2018. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented.

 

See Note 2 and Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

Predecessor and Successor Reporting

 

As a result of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s condensed consolidated financial statements and certain presentations are separated into two distinct periods, the period before the convenience date (labeled Predecessor) and the period after the convenience date (labeled Successor), to indicate the application of different basis of accounting between the periods presented. Despite the separate presentation, there was continuity of the Company’s operations.

 

See Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

Divestitures

 

On August 31, 2018, we closed the sale of certain oil and gas properties in Central Texas and Karnes County, Texas (the “Central Texas Divestiture”) to Magnolia Oil & Gas Parent LLC and Magnolia Oil & Gas Corporation (collectively, “Magnolia”) for total consideration of $133.3 million in cash, net of preliminary purchase price adjustments, and 4.2 million shares of common stock of Magnolia (NYSE: MGY). Based on the closing price for Magnolia’s common stock on August 31, 2018, total consideration was $191.5 million, net of preliminary purchase price adjustments.

  

See Note 6 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

Operating Environment

 

Oil, natural gas and natural gas liquids prices are determined by many factors that are outside of our control. Historically, these prices have been volatile, and we expect them to remain volatile.

 

Continued volatility in prices for oil, natural gas and natural gas liquids could have a material adverse effect on our liquidity and could also have a significant adverse impact on the value and quantities of our reserves, assuming no other changes in our development plans.

 

In order to mitigate the impact of lower prices on our cash flows, we are a party to derivatives, and we intend to enter into derivatives in the future to reduce the impact of price volatility on our cash flows. Although we have entered into derivative contracts covering a portion of our future production through December 2020, a sustained lower price environment would result in lower prices for unprotected volumes and reduce the prices at which we can enter into derivative contracts for additional volumes in the future. We have mitigated, but not eliminated, the potential effects of changing prices on our cash flows from operations for those periods. An extended period of depressed commodity prices would alter our development plans, as well as adversely affect our ability to access additional capital in the capital markets. Please refer to Item 3. “Quantitative And Qualitative Disclosures About Market Risk” in this current report for more information.

 

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 previous year determined using the price on the first day of each month. The prices utilized in calculating our total estimated proved reserves at December 31, 2017 were $51.34 per Bbl of oil and $2.976 per MMBtu of natural gas, which was lower than forward strip prices. Had we used the forward strip prices at December 31, 2017 through December 31, 2030, we estimate that the present value (discounted at 10% per annum) of estimated future net revenues of our proved reserves would have been approximately 6.0% higher and that our reserves on an Mcfe basis would have been approximately 2.6% higher than our reserves calculated using SEC prices.

 

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Our Response to the Operating Environment and Our Operating Plan

 

We focus our efforts on maintaining 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. The primary factors affecting our production levels are capital availability, 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 mitigate or reduce this natural decline through drilling. We will maintain our focus on drilling costs as well as the costs necessary to produce our reserves. Our drilling program is dependent on our capital resources and the economics of drilling prospects 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. From time to time, we may also pursue the strategic divestiture of assets as part of our overall operating plan.

 

RESULTS OF OPERATIONS

 

Factors Affecting the Comparability of the Results

 

Harvest is the successor reporting company of EVEP pursuant to Rule 15d-5 of the Exchange Act; however, the impact to the comparability of our results is generally limited to those areas associated with the basis in and accounting for our oil and gas properties (specifically depreciation, depletion and amortization (“DD&A”) and impairments), exploration expense and income taxes (due to the change from a limited partnership to a corporation that occurred in connection with our emergence from bankruptcy). Accordingly, we believe that describing certain year-over-year variances and trends in our production, revenue and expenses for the three and nine months ended September 30, 2018 and 2017 without regard to the concept of Successor and Predecessor (i.e. on a combined basis) facilitates a meaningful analysis of our results of operations. The results of operations have been derived from our unaudited condensed consolidated financial statements.

 

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The following tables summarize certain of the results of operations and period-to-period comparisons for the periods indicated:

 

   Successor   Predecessor 
   Three Months   Three Months 
   Ended   Ended 
   September 30, 2018   September 30, 2017 
Oil, natural gas and natural gas liquids revenues:          
Oil  $23,254   $13,976 
Natural gas   26,494    26,530 
Natural gas liquids   18,659    11,516 
Total  $68,407   $52,022 
           
Production data:          
Oil (MBbls)   341    310 
Natural gas (MMcf)   10,437    10,263 
Natural gas liquids (MBbls)   611    541 
Total (MMcfe)   16,147    15,373 
           
Average sales price per unit:          
Oil (per Bbl)  $68.20   $45.03 
Natural gas (per Mcf)   2.54    2.59 
Natural gas liquids (per Bbl)   30.55    21.27 
Total (per Mcfe)   4.24    3.38 
           
Expenses and Other:          
Lease operating expenses  $28,281   $26,608 
Cost of purchased natural gas   393    444 
Dry hole and exploration costs   21    135 
Production taxes   2,973    2,573 
Accretion expense on obligations   2,345    1,905 
Depreciation, depletion and amortization   7,860    21,710 
General and administrative expenses   7,673    7,912 
Impairment of oil and natural gas properties   2,565    32 
Gain on sales of oil and natural gas properties   28    876 
Gain (loss) on derivatives, net   (26,423   (152)
Interest expense   3,967    10,092 
Gain on equity securities   4,830    - 
Reorganization items, net   972    - 
           
Net loss  $(9,760)  $(17,888)
           
Average unit cost per Mcfe:          
Production costs:          
Lease operating expenses  $1.75   $1.73 
Production taxes   0.18    0.17 
Total   1.93    1.90 
Depreciation, depletion and amortization   0.49    1.41 
General and administrative expenses   0.48    0.51 

 

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   Successor   Predecessor       Predecessor 
           Combined     
   Four Months   Five Months   Nine Months   Nine Months 
   Ended   Ended   Ended   Ended 
   September 30,   May 31,   September 30,   September 30, 
   2018   2018   2018   2017 
Oil, natural gas and natural gas liquids revenues:                    
Oil  $30,415   $42,460   $72,875   $46,142 
Natural gas   35,158    40,951    76,109    85,742 
Natural gas liquids   24,369    26,896    51,265    31,861 
Total  $89,942   $110,307   $200,249   $163,745 
                     
Production data:                    
Oil (MBbls)   449    662    1,111    1,018 
Natural gas (MMcf)   14,049    16,982    31,031    30,869 
Natural gas liquids (MBbls)   826    1,040    1,866    1,581 
Total (MMcfe)   21,695    27,193    48,888    46,460 
                     
Average sales price per unit:                    
Oil (per Bbl)  $67.80   $64.14   $65.62   $45.34 
Natural gas (per Mcf)   2.50    2.41    2.45    2.78 
Natural gas liquids (per Bbl)   29.51    25.86    27.48    20.15 
Total (per Mcfe)   4.15    4.06    4.10    3.52 
                     
Expenses and Other:                    
Lease operating expenses  $37,656   $45,372   $83,028   $76,782 
Cost of purchased natural gas   522    557    1,079    1,384 
Dry hole and exploration costs   64    122    186    190 
Production taxes   3,943    5,343    9,286    7,828 
Accretion expense on obligations   3,134    3,176    6,310    5,774 
Depreciation, depletion and amortization   10,590    46,196    56,786    70,221 
General and administrative expenses   9,702    15,648    25,350    21,631 
Restructuring costs   -    5,211    5,211    - 
Impairment of oil and natural gas properties   2,565    3    2,568    68,016 
Gain (loss) on sales of oil and natural gas properties   47    (5)   42    911 
Gain (loss) on derivatives, net   (30,655)   444    (30,211)   20,588 
Interest expense   5,166    13,652    18,818    30,501 
Gain on equity securities   4,830    -    4,830    - 
Reorganization items, net   1,780    587,325    589,105    - 
                     
Net loss  $(10,298)  $(610,525)  $(620,823)  $(93,880)
                     
Average unit cost per Mcfe:                    
Production costs:                    
Lease operating expenses  $1.74   $1.67   $1.70   $1.65 
Production taxes   0.18    0.20    0.19    0.17 
Total   1.92    1.87    1.89    1.82 
Depreciation, depletion and amortization   0.49    1.70    1.16    1.51 
General and administrative expenses   0.45    0.58    0.52    0.47 

 

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Three Months Ended September 30, 2018 Compared with the Three Months Ended September 30, 2017

 

Net loss for the three months ended September 30, 2018 was $9.8 million compared with $17.9 million for the three months ended September 30, 2017. The significant factors in this change were a $16.3 million increase in revenues, a $13.9 million decrease in DD&A, a $6.1 million decrease in interest expense and a $4.8 million increase in gain on equity securities, partially offset by a $26.3 million unfavorable change in loss on derivatives.

 

Oil, natural gas and natural gas liquids revenues for the three months ended September 30, 2018 totaled $68.4 million, an increase of $16.4 million compared with the three months ended September 30, 2017. This increase in revenues was the result of an increase of $12.0 million primarily related to higher oil and natural gas liquids prices, an increase of $2.8 million related to increased oil production and an increase of $1.6 million related to the impact of adopting Accounting Standard Update No. 2014-09, Revenue from Contracts with Customers (“Topic 606”).

 

Lease operating expenses for the three months ended September 30, 2018 increased $1.7 million compared with the three months ended September 30, 2017 as the result of $1.6 million related to the impact of adopting Topic 606 combined with a $0.5 million from increased production, offset by $0.4 million from a lower unit cost per Mcfe, excluding the impact of Topic 606. Lease operating expenses were $1.75 per Mcfe in the three months ended September 30, 2018 compared with $1.73 per Mcfe in the three months ended September 30, 2017. 

 

Depreciation, depletion and amortization for the three months ended September 30, 2018 decreased $13.9 million compared with the three months ended September 30, 2017. This decrease was primarily a result of $14.2 million from a lower unit cost per Mcfe, partially offset by $0.3 million from increased production. The lower unit cost was primarily due to lower rates as a result of the application of fresh start accounting during 2018. DD&A was $0.49 per Mcfe in the three months ended September 30, 2018 compared with $1.41 per Mcfe in the three months ended September 30, 2017.

 

General and administrative expenses for the three months ended September 30, 2018 totaled $7.7 million, a decrease of $0.2 million compared with the three months ended September 30, 2017. This decrease is primarily the result of lower legal and accounting fees partially offset by higher fees paid under the Services Agreement (as defined below under “Contractual Obligations”) with EnerVest. General and administrative expenses were $0.48 per Mcfe in the three months ended September 30, 2018 compared with $0.51 per Mcfe in the three months ended September 30, 2017. 

 

During the three months ended September 30, 2018, we incurred proved property impairment of $2.6 million related to proved oil and natural gas properties located in Central Texas and Karnes County, Texas which were sold during August 2018.

 

Gain on equity securities was $4.8 million for the three months ended September 30, 2018. The gain is attributable to the changes in the share price of the shares of common stock of Magnolia which were acquired in the Central Texas Divestiture.

 

Loss on derivatives, net was $26.4 million for the three months ended September 30, 2018 compared with $0.2 million for the three months ended September 30, 2017. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at September 30, 2018 for oil averaged $72.05 per Bbl compared with $68.92 at June 30, 2018, and the 12 month forward prices at September 30, 2018 for natural gas averaged $2.82 per MMBtu compared with $2.89 at June 30, 2018. The 12 month forward price at September 30, 2017 for oil averaged $51.98 per Bbl compared with $47.19 at June 30, 2017, and the 12 month forward prices at September 30, 2017 for natural gas averaged $3.05 per MMBtu compared with $3.09 at June 30, 2017.

 

Interest expense for the three months ended September 30, 2018 decreased $6.1 million compared with the three months ended September 30, 2017. This change was primarily a result of $6.3 million related to a lower weighted average long-term debt balance, partially offset by $0.2 million from a higher weighted average effective interest rate.

 

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We have incurred significant costs associated with the reorganization. Reorganization items, net represent costs and gains directly associated with the Chapter 11 proceedings since the Petition Date. We incurred $1.0 million of reorganization items, net during the three months ended September 30, 2018 related to professional fees. See Note 2 and Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

  

Nine Months Ended September 30, 2018 Compared with the Nine Months Ended September 30, 2017

 

Net loss for the nine months ended September 30, 2018 was $620.8 million compared with $93.9 million for the nine months ended September 30, 2017. The significant factors in this change were $589.1 million of reorganization costs incurred during 2018, a $50.8 million unfavorable change in gain or loss on derivatives and $5.2 million of restructuring costs incurred prior to the Petition Date, partially offset by a $65.4 million decrease in impairment of oil and natural gas properties, a $36.0 million increase in revenues, a $13.4 million decrease in DD&A and an $11.7 million decrease in interest expense.

 

Oil, natural gas and natural gas liquids revenues for the nine months ended September 30, 2018 totaled $200.2 million, an increase of $36.5 million compared with the nine months ended September 30, 2017. This increase in revenues was the result of an increase of $23.3 million primarily related to higher oil and natural gas liquids prices, an increase of $9.1 million primarily related to increased oil and natural gas liquids production and an increase of $4.1 million related to the impact of adopting Topic 606. 

 

Lease operating expenses for the nine months ended September 30, 2018 increased $6.2 million compared with the nine months ended September 30, 2017 as the result of $4.1 million related to the impact of adopting Topic 606 combined with $1.7 million from increased production and $0.4 million from a higher unit cost per Mcfe. Lease operating expenses were $1.70 per Mcfe in the nine months ended September 30, 2018 compared with $1.65 per Mcfe in the nine months ended September 30, 2017. 

 

Depreciation, depletion and amortization for the nine months ended September 30, 2018 decreased $13.4 million compared with the nine months ended September 30, 2017. This decrease was a result of $16.2 million from a lower unit cost per Mcfe, partially offset by $2.8 million related to increased production. The lower unit cost was primarily due to lower rates as a result of the application of fresh start accounting in 2018. DD&A was $1.16 per Mcfe in the nine months ended September 30, 2018 compared with $1.51 per Mcfe in the nine months ended September 30, 2017.

 

General and administrative expenses for the nine months ended September 30, 2018 totaled $25.4 million, an increase of $3.7 million compared with the nine months ended September 30, 2017. This increase is primarily the result of higher compensation expenses as a result of the accelerated vesting of all unvested phantom units as a result of our bankruptcy filing during the nine months ended September 30, 2018 combined with higher fees paid under the Services Agreement with EnerVest. General and administrative expenses were $0.52 per Mcfe in the nine months ended September 30, 2018 compared with $0.47 per Mcfe in the nine months ended September 30, 2017. 

 

Restructuring expenses for the nine months ended September 30, 2018 totaled $5.2 million. These expenses are for professional services related to the Restructuring which were incurred prior to the Petition Date.

 

During the nine months ended September 30, 2018, we incurred proved property impairment of $2.6 million related to proved oil and natural gas properties located in Central Texas and Karnes County, Texas which were sold during August 2018. During the nine months ended September 30, 2017, we incurred proved property impairment of $49.5 million related to proved oil and natural gas properties located in the Mid-Continent area and the Permian Basin, $15.3 million related to proved oil and natural gas properties located in the Monroe Field and $2.9 million related to proved oil and natural gas properties located in East Texas which were sold during April 2017. During the nine months ended September 30, 2017, we also incurred leasehold impairment charges of $0.3 million.

 

Gain on equity securities was $4.8 million for the nine months ended September 30, 2018. The gain is attributable to the changes in the share price of the shares of common stock of Magnolia which were acquired in the Central Texas Divestiture.

 

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Loss on derivatives, net was $30.2 million for the nine months ended September 30, 2018 compared with a gain of $20.6 million for the nine months ended September 30, 2017. This change was attributable to changes in future oil and natural gas prices. The 12 month forward price at September 30, 2018 for oil averaged $72.05 per Bbl compared with $59.40 at December 31, 2017, and the 12 month forward prices at September 30, 2018 for natural gas averaged $2.82 per MMBtu compared with $2.86 at December 31, 2017. The 12 month forward price at September 30, 2017 for oil averaged $51.98 per Bbl compared with $56.19 at December 31, 2016, and the 12 month forward prices at September 30, 2017 for natural gas averaged $3.05 per MMBtu compared with $3.61 at December 31, 2016.

 

Interest expense for the nine months ended September 30, 2018 decreased $11.7 million compared with the nine months ended September 30, 2017. This change was primarily a result of $7.9 million related to a lower weighted average long-term debt balance, $4.7 million related to the suspension of interest for the Senior Notes as a result of the Chapter 11 proceedings and $0.3 million related to the write off of loan costs in the prior year, partially offset by $1.3 million from a higher weighted average effective interest rate.

 

We have incurred significant costs associated with the reorganization. Reorganization items, net represent costs and gains directly associated with the Chapter 11 proceedings since the Petition Date, such as the gain on settlement of liabilities subject to compromise, fresh start valuation adjustments, issuance of common stock and warrants and settlement with Predecessor common unitholders. We incurred $589.1 million of reorganization items, net during the nine months ended September 30, 2018. See Note 2 and Note 3 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

LIQUIDITY AND CAPITAL RESOURCES

 

Prior to our emergence from Chapter 11 bankruptcy, our primary sources of liquidity and capital were issuances of equity and debt securities, borrowings under the Predecessor’s credit facility and cash flows from operations. Our primary uses of cash were 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.

 

Since our emergence from bankruptcy on June 4, 2018, our sources of cash have primarily consisted of proceeds from divestitures of oil and natural gas properties and net cash flows generated from operations. As a result of divesting certain oil and natural gas properties, we have received $136.5 million in cash proceeds. We have used our cash to repay bank debt as well as to fund capital expenditures, principally for the development of our oil and natural gas properties.

 

During the four months ended September 30, 2018, we incurred $16.7 million for capital drilling and completing wells. For the five months ended May 31, 2018, we incurred $26.8 million for capital drilling and completing wells. For 2018, we plan to incur $45 million - $50 million of capital in an effort to keep our production flat, which we expect to fund primarily from cash on hand, sales of assets and net cash flows generated from operations. We will continue monitoring the commodity price environment and expect to retain the financial flexibility to adjust plans in response to market conditions as needed.

 

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

 

We may also utilize borrowings under our Exit Credit Facility and various financing sources available to us, including the issuance of equity or debt securities through public offerings or private placements, to fund any 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 September 30, 2018, we had a $1.0 billion Exit Credit Facility that will mature in February 2021. Borrowings under the Exit Credit Facility may not exceed a “borrowing base” determined by the lenders based on our oil and natural gas reserves. As of September 30, 2018, the borrowing base was $264.7 million, and we had $133.0 million outstanding. On November 6, 2018, we repaid $8.0 million of the outstanding amount.

 

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For additional information about our long–term debt, such as interest rates and covenants, please see Note 10 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein to this report.

 

Cash and Short–term Investments

 

At September 30, 2018, we had $5.7 million of cash and short–term investments, which included $0.6 million of short–term investments. With regard to our short–term investments, we invest in money market accounts with major financial institutions.

 

On August 31, 2018, the Company received 4.2 million shares of common stock of Magnolia as part of the consideration for the Central Texas Divestiture to Magnolia. As of September 30, 2018, the shares have a value of $63.0 million. The Company is subject to a 120 day lock-up after the closing date of August 31, 2018, regarding the sale of these shares. 

 

Counterparty Exposure

 

All of our derivative contracts are with major financial institutions who are also lenders under our Exit 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, 2018, all of our counterparties have performed pursuant to their derivative contracts.

 

Cash Flows

 

Harvest is the successor reporting company of EVEP pursuant to Rule 15d-5 of the Exchange Act; however, the impact to the comparability of our results is generally limited to those areas associated with the basis in and accounting for our oil and gas properties, exploration expense and income taxes (due to the change from a limited partnership to a corporation that occurred in connection with our emergence from bankruptcy). Accordingly, we believe that describing certain year-over-year variances and trends in cash flows for the nine months ended September 30, 2018 and 2017 without regard to the concept of Successor and Predecessor (i.e. on a combined basis) facilitates a meaningful analysis of our cash flows. The cash flows by type of activity have been derived from our unaudited condensed consolidated financial statements.

 

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

 

   Successor   Predecessor       Predecessor 
           Combined     
   Four Months   Five Months   Nine Months   Nine Months 
   Ended   Ended   Ended   Ended 
   September 30, 2018   May 31, 2018   September 30, 2018   September 30, 2017 
Operating activities  $25,925   $21,655   $47,580   $34,336 
Investing activities   115,283    (29,046)   86,237    (67,059)
Financing activities   (164,247   31,227    (133,020)   (11,000)

 

Operating Activities

 

Cash flows from operating activities provided $47.6 million and $34.3 million in the nine months ended September 30, 2018 and 2017, respectively. The significant factors in the change were $36.0 million of higher revenues during 2018, partially offset by $7.2 million change in working capital and $15.8 million increase associated with reorganization items.

 

Investing Activities

 

During the nine months ended September 30, 2018, we spent $52.0 million for additions to our oil and natural gas properties, received $136.5 million in proceeds from the sale of oil and natural gas properties and received $1.7 million from reimbursements related to oil and natural gas properties. During the nine months ended September 30, 2017, we spent $61.4 million for acquisitions of oil and natural gas properties, spent $9.3 million for additions to our oil and natural gas properties and received $3.6 million in proceeds from the sale of oil and natural gas properties.

 

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Financing Activities

 

During the nine months ended September 30, 2018, we received $34.0 million from borrowings under our credit facility, repaid $164.0 million of long-term debt borrowings and paid $2.8 million of debt issuance costs.

 

During the nine months ended September 30, 2017, we received $17.0 million from borrowings under our credit facility and repaid $28.0 million of long-term debt borrowings.

 

Off-Balance Sheet Arrangements

 

In the normal course of business, we may enter into off-balance sheet arrangements that give rise to off-balance sheet obligations. As of September 30, 2018, we have entered into off-balance sheet arrangements which totaled $0.2 million.

 

Contractual Obligations

 

On the Effective Date, we entered into a Services Agreement (the “Services Agreement”) with EnerVest, Ltd. and EnerVest Operating, L.L.C. (together, the “EnerVest Group”). Pursuant to the Services Agreement, the EnerVest Group will provide certain administrative, management, operating and other services and support to us (the “Services”) following the Effective Date. In addition, the EnerVest Group will also provide us with sufficient office space, equipment and office supplies pursuant to the Services Agreement. The Services Agreement covers the people EnerVest employs who provide direct support to our operations; however, the Services Agreement does not cover the six full-time employees of Harvest which include our Chief Executive Officer and Chief Financial Officer. The management fee is subject to an annual redetermination by agreement of the parties and may also be adjusted for acquisitions or divestitures over $5 million. Prior to the Central Texas divestiture, we paid the EnerVest Group a management fee equal to $1,433,333 per month. As a result of the Central Texas divestiture, the fee was reduced by $288,375 per month. Starting in September 2018, we will pay to the EnerVest Group a management fee equal to $1,144,958 per month. The EnerVest Group will provide the Services until December 31, 2020.

 

We have various other contractual obligations in the normal course of our operations. For further information, see our “Management’s Discussion and Analysis of Financial Condition and Results of Operations–Contractual Obligations” in EVEP’s Annual Report on Form 10-K for the year ended December 31, 2017. There have been no material changes to the disclosure since year-end 2017.

 

FORWARD–LOOKING STATEMENTS

 

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

 

·bankruptcy proceedings and the effect of those proceedings on our ongoing and future operations;

 

·our future financial and operating performance and results;

 

·our business strategy and plans, and future capital expenditures, including plans to optimize the value of our assets, including our business strategies post-emergence from bankruptcy;

 

·our estimated net proved reserves, PV–10 value and standardized measure;

 

·our cash flows, liquidity and capital availability;

 

·market prices;

 

·our financial strategy;

 

·our production volumes;

 

·our ability to access the capital markets;

 

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·our future derivative activities; and

 

·our plans and forecasts.

 

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:

 

·our inability to maintain relationships with suppliers, customers, employees and other third parties as a result of our Chapter 11 filing;

 

·Our inability to control our contract operator, EnerVest Operating, outside of the parameters of the Services Agreement;

 

·our need to make accretive acquisitions or substantial capital expenditures to maintain our asset base;

 

·the existence of unanticipated liabilities and problems related to acquired or divested businesses or properties;

 

·the potential for additional impairments due to continuing or future declines in oil, natural gas and natural gas liquids prices;

 

·risks relating to any of our unforeseen liabilities;

 

·fluctuations in prices of oil, natural gas and natural gas liquids and the length of time commodity prices remain depressed;

 

·significant disruptions in the financial markets;

 

·future capital requirements and availability of financing;

 

·uncertainty inherent in estimating our reserves;

 

·risks associated with drilling and operating wells;

 

·discovery, acquisition, development and replacement of reserves;

 

·liquidity and cash flows and their adequacy to fund our ongoing operations;

 

·consequences of changes we have made or may make from time to time in the future, to our capital expenditures budget, including the impact of those changes on our production levels, reserves, results of operations and liquidity;

 

·changes in the financial condition of counterparties;

 

·timing and amount of future production of oil, natural gas and natural gas liquids;

 

·availability of drilling and production equipment;

 

·marketing of oil, natural gas and natural gas liquids;

 

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·developments in oil and natural gas producing countries;

 

·competition;

 

·general economic conditions;

 

·governmental regulations;

 

·activities taken or non–performance by third parties, including suppliers, contractors, operators, transporters and purchasers of our production and counterparties to our derivative financial instrument contracts;

 

·hedging decisions, including whether or not to enter into derivative financial instruments;

 

·actions of third party co–owners of interest in properties in which we also own an interest;

 

·fluctuations in interest rates and the value of the US dollar in international currency markets; and

 

·our ability to effectively integrate companies and properties that we acquire.

 

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 EVEP’s Annual Report on Form 10–K for the year ended December 31, 2017 and in “Item 1A. Risk Factors” contained herein.

 

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

 

ITEM 3. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK

 

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

 

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

 

Commodity Price Risk

 

Our major market risk exposure is to prices for oil, natural gas and natural gas liquids. These prices have historically been volatile. As such, future earnings are subject to change due to changes in these prices. Realized prices are primarily driven by the prevailing worldwide price for oil and regional spot prices for natural gas production. We have used, and expect to continue to use, commodity contracts to reduce our risk of changes in the prices of oil, natural gas and natural gas liquids. Pursuant to our risk management policy, we engage in these activities as a hedging mechanism against price volatility associated with pre–existing or anticipated sales of oil, natural gas and natural gas liquids. Under the Exit Credit Facility, we were required, no later than 60 days following the Effective Date, to hedge (as of the date such swap agreements were executed) no less than 70% of our projected production volumes (excluding projected production volumes from certain properties) for the 18-month period following the Effective Date. We were in compliance with this requirement as of June 30, 2018.

 

We have entered into commodity contracts to hedge a portion of our anticipated oil and natural gas production through December 2020. As of September 30, 2018, we have commodity contracts covering approximately 50% of our estimated production attributable to our net proved reserves from October 2018 through December 2020. Our actual production will vary from the amounts estimated in our reserve reports, perhaps materially.

 

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The fair value of our commodity contracts at September 30, 2018 was a net liability of $28.8 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 $29.9 million.

 

Please see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “Item 1. Condensed Consolidated Financial Statements (Unaudited)” contained herein for additional information.

 

Interest Rate Risk

 

Our floating rate Exit 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 these interest rates. If interest rates on our facility increased by 1%, interest expense for the three and nine months ended September 30, 2018 would have increased by approximately $0.6 million and $2.0 million, respectively.

 

In April 2018, in conjunction with our Chapter 11 filing, the Predecessor terminated its interest rate swaps for the period of April 2018 to September 2020, which resulted in a cash settlement received in April 2018 of $1.6 million. As of September 30, 2018, we did not have any interest rate swaps in place.

 

Please see Note 7 of the Notes to Unaudited Condensed Consolidated Financial Statements included under “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 Rules 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, 2018 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, 2018 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

 

Our business faces many risks. Any of the risks discussed elsewhere in this quarterly report and our other SEC filings could have a material impact on our business, financial position or results of operations. Additional risks and uncertainties not presently known to us or that we currently believe to be immaterial may also impair our business operations. There have been no material changes with respect to the risk factors disclosed in EV Energy Partners, L.P.’s Annual Report on Form 10–K for the year ended December 31, 2017, and our Quarterly Report on Form 10-Q for the fiscal quarter ended June 30, 2018.

 

 44 

 

  

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

 

The Company repurchased the following shares from employees during the three months ended September 30, 2018 for the payment of withholding taxes due on shares of restricted stock that vested and were issued under its share-based compensation plan.

 

   Total Number of   Average Price Paid 
Period  Shares Purchased   Per Share 
September 2018   12,348   $19.99 

 

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:

 

3.1 Amended and Restated Certificate of Incorporation of Harvest Oil & Gas Corp. (incorporated by reference to Exhibit 4.1 of the Company’s registration statement on Form S-8 filed on June 4, 2018).
   
3.2 Certificate of Designations, Preferences and Rights of 8% Cumulative Nonparticipating Redeemable Series A Preferred Stock of Harvest Oil & Gas Corp. (incorporated by reference to Exhibit 3.2 to Current Report on Form 8-K filed on June 4, 2018).
   
3.3 Amended and Restated Bylaws of Harvest Oil & Gas Corp. (incorporated by reference to Exhibit 4.2 of the Company’s registration statement on Form S-8 filed on June 4, 2018).
   
3.4 State of Delaware Certificate of Change of Registered Agent and/or Registered Office, dated August 1, 2018 (incorporated by reference to Exhibit 3.4 to Quarterly Report on Form 10-Q filed on August 20, 2018).
   
10.1 Contribution and Membership Interest Purchase Agreement, dated August 20, 2018 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on August 21, 2018).
   
10.2 First Amendment to Services Agreement, dated August 17, 2018, by and between Harvest Oil & Gas Corp., EnerVest, Ltd. and EnerVest Operating, L.L.C. (incorporated by reference to Exhibit 10.2 to Current Report on Form 8-K filed on August 21, 2018).
   
10.3 Form of Restricted Stock Unit Agreement under the 2018 Omnibus Incentive Plan (incorporated by reference to Exhibit 10.3 to Current Report on Form 8-K filed on August 21, 2018).
   
10.4 Employment Agreement between the Company and Ryan Stash, dated October 26, 2018 (incorporated by reference to Exhibit 10.1 to Current Report on Form 8-K filed on October 29, 2018).
   
+31.1 Rule 13a-14(a)/15d–14(a) Certification of Chief Executive Officer.
   
+31.2 Rule 13a-14(a)/15d–14(a) Certification of Chief Financial Officer.

 

 45 

 

 

+32.1 Section 1350 Certification of Chief Executive Officer.
   
+32.2 Section 1350 Certification of Chief Financial Officer.
   
+101 Interactive Data Files.

 

 

+Filed herewith

 

 46 

 

  

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.

 

  Harvest Oil & Gas Corp. 
  (Registrant) 

 

Date: November 13, 2018 By: /s/ RYAN STASH
    Ryan Stash
    Vice President and Chief Financial Officer

 

 47 

 

Exhibit 31.1 

 

CERTIFICATIONS

 

I, Michael E. Mercer, certify that:

 

1.I have reviewed this quarterly report on Form 10–Q of Harvest Oil & Gas Corp.;

 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

 

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: November 13, 2018 /s/ MICHAEL E. MERCER  
  Michael E. Mercer  
  Chief Executive Officer  

 

   

 

Exhibit 31.2 

 

CERTIFICATIONS

 

I, Ryan Stash, certify that:

 

1.I have reviewed this quarterly report on Form 10–Q of Harvest Oil & Gas Corp.;

 

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

 

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

 

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

 

a)Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

 

b)Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles; 

 

c)Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

 

d)Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

 

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

 

a)All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

 

b)Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

 

Date: November 13, 2018 /s/ RYAN STASH  
  Ryan Stash  
  Vice President and Chief Financial Officer  

 

   

 

Exhibit 32.1 

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 

 

In connection with the accompanying report on Form 10–Q for the period ended September 30, 2018 of Harvest Oil & Gas Corp. (the “Company”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Michael E. Mercer, Chief Executive Officer, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002, that: 

 

the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 

 

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. 

 

Date: November 13, 2018 /s/ MICHAEL E. MERCER  
  Michael E. Mercer  
  Chief Executive Officer  

 

   

 

Exhibit 32.2 

 

CERTIFICATION PURSUANT TO

18 U.S.C. SECTION 1350,

AS ADOPTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 

 

In connection with the accompanying report on Form 10–Q for the period ended September 30, 2018 of Harvest Oil & Gas Corp. (the “Company”) and filed with the Securities and Exchange Commission on the date hereof (the “Report”), I, Ryan Stash, Vice President and Chief Financial Officer, hereby certify, pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes–Oxley Act of 2002, that: 

 

the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and 

 

the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

 

Date: November 13, 2018 /s/ RYAN STASH  
  Ryan Stash  
  Vice President and Chief Financial Officer