hrst_Current_Folio_10K

Table of Contents

 

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

Form 10–K

 

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

 

For the fiscal year ended December 31, 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

 

Securities registered pursuant to Section 12(b) of the Act: None

 

Securities registered pursuant to Section 12(g) of the Act:  None

 

Indicate by check mark if the registrant is a well–known seasoned issuer, as defined in Rule 405 of the Securities Act. YES  ☐  NO  ☑

 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. YES  ☐  NO  ☑

 

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  ☑  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  ☑  NO  ☐

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S–K (§ 229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10‑K or any amendment to this Form 10–K.  ☑

 

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 ☑ 

 

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  ☑

 

Indicate by check mark whether the registrant has filed all documents and reports required to be filed by Section 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  ☑  NO  ☐

 

As of June 29, 2018, the last business day of the registrant’s most recently completed second quarter, the registrant’s equity was not listed on a domestic exchange or over-the-counter market. The registrant’s common stock began trading on the OTCQX U.S. Premier Marketplace on September 20, 2018.

 

As of March 22, 2019, the registrant had 10,042,468 shares of common stock outstanding.

 

DOCUMENTS INCORPORATED BY REFERENCE:

Portions of the registrant’s definitive proxy statement for its 2019 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2018, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

 


 

Table of Contents

Table of Contents

 

 

 

 

 

 

 

    

PART I

    

 

 

 

 

 

 

Item 1. 

 

Business

 

7

Item 1A. 

 

Risk Factors

 

29

Item 1B. 

 

Unresolved Staff Comments

 

50

Item 2. 

 

Properties

 

50

Item 3. 

 

Legal Proceedings

 

50

Item 4. 

 

Mine Safety Disclosures

 

50

 

 

 

 

 

 

 

PART II

 

50

 

 

 

 

 

Item 5. 

 

Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 

50

Item 6. 

 

Selected Financial Data

 

53

Item 7. 

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations

 

54

Item 7A. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

70

Item 8. 

 

Financial Statements and Supplementary Data

 

72

Item 9. 

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

117

Item 9A. 

 

Controls and Procedures

 

117

Item 9B. 

 

Other Information

 

117

 

 

 

 

 

 

 

PART III

 

118

 

 

 

 

 

Item 10. 

 

Directors, Executive Officers and Corporate Governance

 

118

Item 11. 

 

Executive Compensation

 

118

Item 12. 

 

Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 

118

Item 13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

118

Item 14. 

 

Principal Accounting Fees and Services

 

118

 

 

 

 

 

 

 

PART IV

 

119

 

 

 

 

 

Item 15. 

 

Exhibits, Financial Statement Schedules

 

119

Item 16. 

 

Form 10-K Summary

 

121

 

 

 

 

 

Signatures 

 

122

 

 

 

 

 

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GLOSSARY OF OIL AND NATURAL GAS TERMS

 

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

 

Bcf. One billion cubic feet of natural gas.

 

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

 

Btu. A British thermal unit is a measurement of the heat generating capacity of natural gas. One Btu is the heat required to raise the temperature of a one–pound mass of pure liquid water one degree Fahrenheit at the temperature at which water has its greatest density (39 degrees Fahrenheit).

 

Completion. Installation of permanent equipment for production of oil or gas, or, in the case of a dry well, reporting to the appropriate authority that the well has been abandoned.

 

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

 

Developed oil and gas reserves. Reserves of any category that can be expected to be recovered:

 

through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well, and

 

through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

 

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas. More specifically, development costs, including depreciation and applicable operating costs of support equipment and facilities and other costs of development activities, are costs incurred to:

 

gain access to and prepare well locations for drilling, including surveying well locations for the purpose of determining specific development drilling sites, clearing ground, draining, road building, and relocating public roads, gas lines, and power lines, to the extent necessary in developing the proved reserves;

 

drill, fracture, stimulate and equip development wells, development-type stratigraphic test wells, and service wells, including the costs of platforms and of well equipment such as casing, tubing, pumping equipment, and the wellhead assembly;

 

acquire, construct, and install production facilities such as lease flow lines, separators, treaters, heaters, manifolds, measuring devices, production storage tanks, natural gas cycling and processing plants, and central utility and waste disposal systems; and

 

provide improved recovery systems.

 

Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

 

Dry hole or well. An exploratory, development or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as a producing oil or gas well.

 

Exploration costs.  Costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects of containing oil and natural gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.

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Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.

 

Field. An area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature or stratigraphic condition.

 

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

 

MBbls. One thousand barrels of oil or other liquid hydrocarbons.

 

Mcf. One thousand cubic feet of natural gas.

 

Mcfe. One thousand cubic feet equivalent of natural gas, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas. The ratio of six Mcf of natural gas to one Bbl of oil or natural gas liquids is commonly used in the oil and natural gas business and represents the approximate energy equivalency of six Mcf of natural gas to one Bbl of oil or natural gas liquids, and does not represent the sales price equivalency of natural gas to oil or natural gas liquids.

 

MMBbls. One million barrels of oil or other liquid hydrocarbons.

 

MMBtu. One million British thermal units.

 

MMcf. One million cubic feet of natural gas.

 

MMcfe. One million cubic feet equivalent of natural gas, determined using the ratio of one Bbl of oil, condensate or natural gas liquids to six Mcf of natural gas.

 

Natural gas liquids. The hydrocarbon liquids contained within natural gas.

 

Net acres or net wells. The sum of the fractional working interests owned in gross acres or gross wells, as the case may be.

 

NYMEX. The New York Mercantile Exchange.

 

Oil. Crude oil and condensate.

 

Overriding royalty interest (“ORRI”). Fractional, undivided interests or rights of participation in the oil and natural gas, or in the proceeds from the sale of oil and natural gas, produced from a specified tract or tracts, which are limited in duration to the terms of an existing lease and which are not subject to any portion of the expense of development, operation or maintenance.

 

Production costs. Costs incurred to operate and maintain wells and related equipment and facilities, including depreciation and applicable operating costs of support equipment and facilities and other costs of operating and maintaining those wells and related equipment and facilities. They become part of the cost of oil and gas produced. Examples of production costs (sometimes called lifting costs) are:

 

costs of labor to operate the wells and related equipment and facilities;

 

repairs and maintenance;

 

materials, supplies, and fuel consumed and supplies utilized in operating the wells and related equipment and facilities;

 

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property taxes and insurance applicable to proved properties and wells and related equipment and facilities; and

 

severance taxes.

 

Productive well. An exploratory, development or extension well that is not a dry well.

 

Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well. Additional reserves expected to be obtained through the application of fluid injection or other improved recovery techniques for supplementing the natural forces and mechanisms of primary recovery are included in “proved developed reserves” only after testing by a pilot project or after the operation of an installed program has confirmed through production response that increased recovery will be achieved.

 

Proved reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward from known reservoirs, and under existing economic conditions, operating methods and government regulations –  prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

 

Proved undeveloped reserves (“PUDs”). Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having PUDs only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. Estimates for PUDs are not attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

 

Recompletion. The completion for production of an existing wellbore in another formation from that which the well has been previously completed.

 

Reserves. Estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

 

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reserves.

 

Standardized measure. The after-tax present value of estimated future net cash flows to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the Securities and Exchange Commission (the “SEC”), using prices and costs employed in the determination of proved reserves, without giving effect to non–property related expenses such as certain general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%.

 

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of natural gas and oil regardless of whether such acreage contains proved reserves.

 

Undeveloped oil and gas reserves. Reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

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Working interest. The operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and a share of production.

 

Workover. Operations on a producing well to restore or increase production.

 

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PART I

 

ITEM 1. BUSINESS

 

Overview

 

Harvest Oil & Gas Corp. (“Harvest” or “Successor”), a Delaware corporation, is an independent oil and natural gas company that was formed in 2018 in connection with the reorganization of EV Energy Partners, L.P. (“EVEP,” “Partnership” or “Predecessor”). As used herein, the terms the “Company,” “we,” “our” or “us” refer to (i) Harvest Oil & Gas Corp. after the Effective Date (as defined below) and (ii) EVEP prior to, and including, the Effective Date, in each case, together with their respective consolidated subsidiaries or on an individual basis, depending on the context in which the statements are made.

 

We operate one reportable segment engaged in the development and production of oil and natural gas properties. As of December 31, 2018, 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, 2018, we had estimated net proved reserves of 711.9 Bcfe and a standardized measure of $436.4 million. Of our total net proved reserves, 98% are proved developed, 67% are natural gas and 53% are operated.

 

As a result of the ongoing review of our asset base in order to maximize shareholder value, we have initiated processes to divest certain assets and in the future may look to divest additional assets or all of our remaining assets and use the proceeds to repay bank debt, return capital to shareholders, concentrate in existing positions or venture into new basins. In January and February 2019, we entered into definitive agreements to sell all of our oil and gas properties in the San Juan Basin and certain of our oil and gas properties in the Mid-Continent area. See “—Current Developments—Divestitures” below for additional information.

 

Emergence from Voluntary Reorganization under Chapter 11

 

On March 13, 2018, EVEP and 13 affiliated debtors (collectively, the “Debtors”) entered into a Restructuring Support Agreement (the “Restructuring Support Agreement”) with certain holders of the Predecessor’s notes, certain lenders under the Predecessor’s reserve-based lending facility, EnerVest, Ltd. (“EnerVest”) and 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 United States Bankruptcy Court for the District of Delaware (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. During the pendency of the Chapter 11 proceedings, EVEP continued to operate its business 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 “Debtors-in-Possession.” On May 17, 2018, the Bankruptcy Court entered an order confirming the Plan.

 

On June 4, 2018 (the “Effective Date”), the Debtors satisfied the conditions to effectiveness of the Debtors’ First Modified Joint Prepackaged Plan of Reorganization (as amended, modified and supplemented from time to time, the “Plan”), and the Plan became effective in accordance with its terms. In accordance with the Plan, EVEP’s equity was cancelled, EVEP transferred all of its assets and operations to Harvest, EVEP was dissolved and Harvest became the successor reporting company to EVEP pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). See Note 2 and Note 3 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Predecessor and Successor Reporting

 

Upon emergence from bankruptcy on the Effective Date, we elected to adopt fresh start accounting effective May 31, 2018 (the “convenience date”) to coincide with the timing of the Company’s normal accounting period close. As a result

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of the adoption of fresh start accounting and the effects of the implementation of the Plan, the Company’s 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 Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Current Developments

 

Our Operating Plan and Strategy

 

We focus our efforts on maintaining or minimizing the decline in 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. As initial reservoir pressures are depleted, production from our wells decreases. We attempt to mitigate or reduce this natural decline through drilling or workover operations. 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 inventory and economics of drilling prospects and can be limited by many factors, including our ability to timely obtain drilling permits and regulatory approvals. Our overall operating plan also includes regular reviews of our asset base. As a result of this ongoing review, we have initiated processes to divest of certain assets, and in the future, we may look to divest additional assets or all of our remaining assets in order to maximize shareholder value.

 

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 7A. “Quantitative And Qualitative Disclosures About Market Risk” contained herein for more information.

 

Divestitures

 

In August 2018, we closed the sale of certain oil and gas properties in Central Texas and Karnes County, Texas to Magnolia Oil & Gas Parent LLC and Magnolia Oil & Gas Corporation (collectively, “Magnolia”) for total consideration of $134.4 million in cash, net of 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 $192.7 million, net of purchase price adjustments.

 

During January 2019, we sold all of our 4.2 million shares of common stock of Magnolia for net proceeds of $51.7 million.

 

In addition, in August 2018, we closed the sale of certain oil and gas properties in Central Texas to a third party for total consideration of $3.4 million, net of purchase price adjustments.

 

In December 2018, we closed the sale of certain oil and gas properties in Central Texas to a third party for total consideration of $2.6 million, net of preliminary purchase price adjustments.

 

In addition, in December 2018, we closed the sale of certain oil and gas properties in the Mid–Continent area to a third party for total consideration of $1.0 million, net of purchase price adjustments.

 

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In January 2019, we closed the sale of certain oil and gas properties in the Mid-Continent area to a third party for total consideration of $1.7 million, net of preliminary purchase price adjustments.

 

In February 2019, we entered into a definitive agreement to sell all of our (i) oil and gas properties in the San Juan Basin and (ii) membership interests in EnerVest Mesa, LLC, a wholly-owned subsidiary of EV Properties, L.P., to a third party for total consideration of $42.8 million in cash, subject to purchase price adjustments. The transaction is expected to close in April 2019 and has an effective date of October 1, 2018.

 

Also, in February 2019, we entered into a definitive agreement to sell certain oil and gas properties in the Mid-Continent area to a third party for total consideration of $2.5 million in cash, subject to purchase price adjustments. The transaction is expected to close in April 2019 and has an effective date of October 1, 2018.

 

See Note 8 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Our Relationship with EnerVest

 

As a result of the Restructuring, EnerVest is no longer a related party to the Company. However, we continue to have a relationship with EnerVest through a services agreement entered into in connection with the Restructuring (the “Services Agreement”) pursuant to which EnerVest operates the majority of our properties and provides other administrative services. See Note 13 and 17 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information regarding the Services Agreement and the related party status of EnerVest, respectively.

 

Oil and Natural Gas Operations and Properties

 

At December 31, 2018, our oil and natural gas properties were located in the Barnett Shale, the San Juan Basin, the Appalachian Basin (which includes the Utica Shale), Michigan, the Mid–Continent areas in Oklahoma, Texas, Arkansas, Kansas and Louisiana, the Permian Basin and the Monroe Field in Northern Louisiana.

 

Barnett Shale

 

Our properties are primarily located in Denton, Montague, Parker, Tarrant and Wise counties in Northern Texas. Our estimated net proved reserves as of December 31, 2018 were 280.1 Bcfe, 62% of which is natural gas. During 2018, we drilled 15 gross wells (4.7 net wells) in the Barnett Shale, which were successfully completed. As of December 31, 2018, we owned an average 28% working interest in 1,356 gross productive wells in this area.

 

San Juan Basin

 

Our properties are primarily located in Rio Arriba County, New Mexico and La Plata County in Colorado. Our estimated net proved reserves as of December 31, 2018 were 157.6 Bcfe, 64% of which is natural gas. During 2018, we did not drill any wells in the San Juan Basin. As of December 31, 2018, we owned an average 81% working interest in 496 gross productive wells in this area. In February 2019, we entered into a definitive agreement to sell all of our oil and gas properties in the San Juan Basin. See —Current Developments—Divestitures” above for additional information.

 

Appalachian Basin (including the Utica Shale)

 

Our activities are concentrated in the Ohio and West Virginia areas of the Appalachian Basin. Our Ohio area properties are producing primarily from the Knox and Clinton formations and other Devonian age sands in 40 counties in Eastern Ohio and 8 counties in Western Pennsylvania. Our West Virginia area properties are producing primarily from the Balltown, Benson and Big Injun formations in 22 counties in North Central West Virginia. Our estimated net proved reserves as of December 31, 2018 were 129.2 Bcfe, 68% of which is natural gas. During 2018, we drilled 1 gross well (0.9 net wells) in the Appalachian Basin. As of December 31, 2018, we owned an average 64% working interest in 10,424 gross productive wells in this area.

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Michigan

 

Our properties are located in the Antrim Shale reservoir in Otsego and Montmorency counties in northern Michigan. Our estimated net proved reserves as of December 31, 2018 were 64.5 Bcfe, 98% of which is natural gas. During 2018, we did not drill any wells in Michigan. As of December 31, 2018, we owned an average 65% working interest in 1,502 gross productive wells in this area.

 

Mid–Continent Area

 

Our properties are primarily located in 43 counties in Oklahoma, 22 counties in Texas, four parishes in North Louisiana, two counties in Kansas and six counties in Arkansas. Our estimated net proved reserves as of December 31, 2018 were 31.2 Bcfe, 58% of which is natural gas. During 2018, we did not drill any wells in the Mid-Continent area. As of December 31, 2018, we owned an average 16% working interest in 1,666 gross productive wells in this area. In January and February 2019, we entered into definitive agreements to sell certain of our oil and gas properties in the Mid-Continent area. Our estimated net proved reserves as of December 31, 2018, for the properties to be sold are 9.5 Bcfe, 55% of which is natural gas. See —Current Developments—Divestitures” above for additional information.

 

Permian Basin

 

Our properties are primarily located in the Yates, Seven Rivers, Queen, Morrow, Clear Fork and Wichita Albany formations in four counties in New Mexico and Texas. Our estimated net proved reserves as of December 31, 2018 were 28.1 Bcfe, 38% of which is natural gas. During 2018, we did not drill any wells in the Permian Basin. As of December 31, 2018, we owned an average 97% working interest in 136 gross productive wells in this area.

 

Monroe Field

 

Our properties are primarily located in two parishes in Northeast Louisiana. Our estimated net proved reserves as of December 31, 2018 were 21.2 Bcfe, 100% of which is natural gas. During 2018, we did not drill any wells in the Monroe Field. As of December 31, 2018, we owned an average 98% working interest in 3,831 gross productive wells in this area.

 

Our Oil, Natural Gas and Natural Gas Liquids Data

 

Our Reserves

 

Oil, natural gas and natural gas liquids reserve information presented herein is derived from our reserve reports prepared by Cawley, Gillespie & Associates, Inc. (“Cawley Gillespie”) and Wright & Company, Inc. (“Wright”), our independent reserve engineers. All of our proved reserves are located in the United States. The following table presents our estimated net proved reserves at December 31, 2018:

 

 

 

 

 

 

 

 

 

 

 

    

 

    

 

    

Natural Gas

    

 

 

 

 

 

Natural Gas

 

Liquids

 

 

 

 

Oil (MMBbls)

 

(Bcf)

 

(MMBbls)

 

Bcfe

Proved reserves:

 

  

 

  

 

  

 

  

Developed

 

9.9

 

468.5

 

28.5

 

698.5

Undeveloped

 

 —

 

8.2

 

0.8

 

13.4

Total

 

9.9

 

476.7

 

29.3

 

711.9

 

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In addition, the following table summarizes information about our proved reserves by geographic region as of December 31, 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Estimated Net Proved Reserves

 

    

 

    

 

    

Natural Gas

    

 

 

 

Oil

 

Natural Gas 

 

Liquids

 

 

 

 

(MMBbls)

 

(Bcf)

 

(MMBbls)

 

Bcfe

Barnett Shale

 

0.2

 

175.0

 

17.3

 

280.1

San Juan Basin (1)

 

1.3

 

100.4

 

8.2

 

157.6

Appalachian Basin

 

6.4

 

87.9

 

0.5

 

129.2

Michigan

 

0.1

 

63.2

 

0.1

 

64.5

Mid–Continent area (2)

 

1.5

 

18.2

 

0.7

 

31.2

Permian Basin

 

0.4

 

10.8

 

2.5

 

28.1

Monroe Field

 

 —

 

21.2

 

 —

 

21.2

Total

 

9.9

 

476.7

 

29.3

 

711.9


(1)In February 2019, we entered into a definitive agreement to sell all of our oil and gas properties in the San Juan Basin. See “—Current Developments—Divestitures” below for additional information.

 

(2)In January and February 2019, we entered into definitive agreements to sell certain of our oil and gas properties in the Mid-Continent area. These properties included estimated net proved reserves of 9.5 Bcfe, 55% of which is natural gas, as of December 31, 2018. See —Current Developments—Divestitures” above for additional information.

 

Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods. PUDs are proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. See “Glossary of Oil and Natural Gas Terms.” Proved undeveloped locations conform to the SEC rules defining proved undeveloped locations. We do not have any reserves that would be classified as synthetic oil or synthetic natural gas.

 

Our estimates of proved reserves are based on the quantities of oil, natural gas and natural gas liquids which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations – prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimate. Reserves for proved developed producing wells were estimated using production performance and material balance methods. Certain new producing properties with little production history were forecast using a combination of production performance and analogy to offset production, both of which are believed to provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either or both volumetric or analogy methods. These methods are believed to provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

 

The data in the above tables represents estimates only. Oil, natural gas and natural gas liquids reserve engineering is inherently a subjective process of estimating underground accumulations of oil, natural gas and natural gas liquids that cannot be measured exactly. The accuracy of any reserve estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserve estimates may vary from the quantities of oil, natural gas and natural gas liquids that are ultimately recovered. Please read “Item 1A. Risk Factors.”

 

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The standardized measure of discounted future net cash flows is the after-tax present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with the rules and regulations of the SEC, without giving effect to non–property related expenses such as general and administrative expenses and debt service or to depreciation, depletion and amortization and discounted using an annual discount rate of 10%. Future income tax expenses are calculated by applying the year-end statutory tax rates to the pre-tax net cash flows. Standardized measure does not give effect to derivative transactions. The standardized measure shown should not be construed as the current market value of the reserves. The 10% discount factor, which is required by Financial

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Accounting Standards Board pronouncements, is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

 

At December 31, 2018, our proved reserves had a standardized measure of discounted future net cash flows of $436.4 million and a present value of future net pre-tax cash flows attributable to estimated net proved reserves, discounted at 10% per annum (“PV-10”) of $509.6 million. PV–10, is a computation of the standardized measure of discounted future net cash flows on a pre–tax basis and is computed on the same basis as standardized measure but does not include a provision for federal income taxes, Texas gross margin tax or other state taxes. PV–10 is considered a non–GAAP financial measure under the regulations of the SEC. We believe PV–10 to be an important measure for evaluating the relative significance of our oil and natural gas properties. We further believe investors and creditors may utilize our PV–10 as a basis for comparison of the relative size and value of our reserves to other companies. PV–10, however, is not a substitute for the standardized measure. Our PV–10 measure and standardized measure do not purport to present the fair value of our reserves.

 

The table below provides a reconciliation of PV–10 to the standardized measure at December 31, 2018 (dollars in millions):

 

 

 

 

 

Standardized measure

    

$

436.4

Future income taxes, discounted at 10%

 

 

73.2

PV-10

 

$

509.6

 

Our Proved Undeveloped Reserves

 

We annually review all PUDs to ensure an appropriate plan for development exists. As of December 31, 2017, the Predecessor had no reportable estimated PUDs with respect to any of its properties due to uncertainty regarding the Predecessor’s ability to continue as a going concern and the availability of capital that would be required to develop the PUD reserves.

 

At December 31, 2018 (Successor), we had 13.4 Bcfe of PUDs compared with zero PUDs at December 31, 2017 (Predecessor). The following table describes the changes in PUDs during 2018:

 

 

 

 

 

    

Bcfe

PUDs as of December 31, 2017 (Predecessor)

 

 —

Revisions of previous estimates

 

66.7

Sales of minerals in place

 

(53.3)

PUDs as of December 31, 2018 (Successor)

 

13.4

 

The following describes the material changes to our PUDs during 2018:

 

Revisions of previous estimates. This change from prior estimates primarily results from our emergence from bankruptcy on June 4, 2018 and the availability of capital required to develop the PUDs within the SEC five-year development limitation on PUDs.

 

Sales of minerals in place. In August 2018, we sold oil and natural gas properties in Central Texas and Karnes County, Texas, which included 53.3 Bcfe of PUDs.

 

Internal Controls Applicable to our Reserve Estimates

 

Our policies and procedures regarding internal controls over the recording of our reserves is structured to objectively and accurately estimate our reserves quantities and present values in compliance with both accounting principles generally accepted in the United States and the SEC’s regulations. Compliance with these rules and regulations is the responsibility of Terry Wagstaff, our Vice President of Acquisitions and Engineering, who is also our principal engineer. Mr. Wagstaff has over 35 years of experience in the oil and natural gas industry, with exposure to reserves and reserve related valuations

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and issues during most of this time, and is a qualified reserves estimator (“QRE”), as defined by the standards of the Society of Petroleum Engineers. Further professional qualifications include a Bachelor of Science in Petroleum Engineering, extensive internal and external reserve training, asset evaluation and management, and he is a registered professional engineer in the state of Texas. In addition, our principal engineer is an active participant in industry reserve seminars, professional industry groups, and is a member of the Society of Petroleum Engineers.

 

Our controls over reserve estimates included retaining Cawley Gillespie and Wright as our independent petroleum engineers. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Cawley Gillespie and Wright, and they prepared their own estimates of 44% and 56%, respectively, of our reserves attributable to our properties. All of the information regarding reserves in this annual report on Form 10–K is derived from the reports of Cawley Gillespie and Wright, which are included as exhibits to this annual report on Form 10–K.

 

The principal engineer at Cawley Gillespie responsible for preparing our reserve estimates is W. Todd Brooker, a President and Principal with Cawley Gillespie. Mr. Brooker is a licensed professional engineer in the state of Texas (license #83462) with over 25 years of experience in petroleum engineering. The principal engineer at Wright responsible for preparing our reserve estimates is D. Randall Wright, the President of Wright. Mr. Wright is a licensed professional engineer in the state of Texas (license #43291) with over 45 years of experience in petroleum engineering.

 

We and EnerVest maintain an internal staff of petroleum engineers, geoscience professionals and petroleum landmen who work closely with Cawley Gillespie and Wright to ensure the integrity, accuracy and timeliness of data furnished to Cawley Gillespie and Wright in their reserves estimation process. Our Vice President of Acquisitions and Engineering reviews and approves the reserve information compiled by our internal staff. Our technical team meets regularly with representatives of Cawley Gillespie and Wright to review properties and discuss the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates. Our technical team and Vice President of Acquisitions and Engineering also meet regularly to review the methods and assumptions used by Cawley Gillespie and Wright in their preparation of the year end reserves estimates.

 

The audit committee of our board of directors meets with management, including the Vice President of Acquisitions and Engineering, to discuss matters and policies related to our reserves.

 

Our Productive Wells

 

The following table sets forth information relating to the productive wells in which we owned a working interest as of December 31, 2018. Productive wells consist of producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of productive wells in which we have a working interest, regardless of our percentage interest. A net well is not a physical well, but is a concept that reflects the actual total working interest we hold in a given well. We compute the number of net wells we own by totaling the percentage interests we hold in all our gross wells. Operated wells are the wells operated by EnerVest in which we own an interest.

 

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Our wells may produce both oil and natural gas. We classify a well as an oil well if the net equivalent production of oil was greater than natural gas for the well.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Wells

 

Net Wells

 

   

 

   

Natural 

   

 

   

 

   

Natural

   

 

 

 

Oil

 

Gas

 

Total

 

Oil

 

 Gas

 

Total

Barnett Shale:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Non–operated

 

19

 

1,337

 

1,356

 

 4

 

374

 

378

San Juan Basin: (1)

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

20

 

400

 

420

 

20

 

367

 

387

Non–operated

 

23

 

53

 

76

 

 2

 

11

 

13

Appalachian Basin:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

1,733

 

4,757

 

6,490

 

1,686

 

4,503

 

6,189

Non–operated

 

428

 

3,506

 

3,934

 

33

 

445

 

478

Michigan:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 1

 

1,204

 

1,205

 

 1

 

958

 

959

Non–operated

 

29

 

268

 

297

 

 1

 

11

 

12

Mid–Continent area: (2)

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

56

 

109

 

165

 

45

 

70

 

115

Non–operated

 

630

 

871

 

1,501

 

44

 

106

 

150

Permian Basin:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 1

 

132

 

133

 

 1

 

129

 

130

Non–operated

 

 3

 

 —

 

 3

 

 1

 

 —

 

 1

Monroe Field:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 —

 

3,831

 

3,831

 

 —

 

3,744

 

3,744

Non–operated

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Total (3)

 

2,943

 

16,468

 

19,411

 

1,838

 

10,718

 

12,556

(1)In February 2019, we entered into a definitive agreement to sell all of our oil and gas properties in the San Juan Basin. See —Current Developments—Divestitures” above for additional information.

 

(2)In January and February 2019, we entered into definitive agreements to sell certain of our oil and gas properties in the Mid-Continent area. These properties included 632 gross non-operated wells (57 net non-operated wells) as of December 31, 2018. See —Current Developments—Divestitures” above for additional information.

 

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

 

Our Developed and Undeveloped Acreage

 

The following table sets forth information relating to our leasehold acreage as of December 31, 2018:

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acreage

 

Undeveloped Acreage

 

   

Gross

   

Net

   

Gross

   

Net

Barnett Shale

 

151,329

 

38,075

 

12,947

 

2,583

San Juan Basin (1)

 

139,047

 

63,246

 

34,110

 

26,933

Appalachian Basin

 

614,183

 

467,798

 

320,269

 

258,273

Michigan

 

87,903

 

63,420

 

1,038

 

1,035

Mid–Continent area (2)

 

295,076

 

55,191

 

11,506

 

834

Permian Basin

 

11,695

 

10,868

 

520

 

385

Monroe Field (3)

 

5,904

 

5,904

 

170,346

 

145,666

Total

 

1,305,137

 

704,502

 

550,736

 

435,709

(1)In February 2019, we entered into a definitive agreement to sell all of our oil and gas properties in the San Juan Basin. See —Current Developments—Divestitures” above for additional information.

 

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(2)In January and February 2019, we entered into definitive agreements to sell certain of our oil and gas properties in the Mid-Continent area. These properties included 59,558 gross developed acres (17,500 net developed acres) and 680 gross undeveloped acres (198 net undeveloped acres) as of December 31, 2018. See —Current Developments—Divestitures” above for additional information.

 

(3)There are no spacing requirements on substantially all of the wells on our Monroe Field properties; therefore, one developed acre is assigned to each productive well for which there is no spacing unit assigned.

 

Substantially all of our acreage is held by production, which means that as long as our wells on the acreage continue to produce, we will continue to hold the leases. The acreage in which we hold interests that are not held by production are not significant to our overall undeveloped acreage.

 

Title to Properties

 

As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved reserves. Prior to the commencement of drilling operations on those properties, we conduct a thorough title examination and perform curative work with respect to significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing any title defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. Prior to completing an acquisition of producing leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or review previously obtained title opinions. As a result, we have obtained title opinions on a significant portion of our properties and believe that we have satisfactory title to our producing properties in accordance with standards generally accepted in the oil and natural gas industry. Our properties are subject to customary royalty and other interests, liens for current taxes and other burdens that we believe do not materially interfere with the use of or affect our carrying value of the properties.

 

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Production, Average Sales Price and Average Production Cost by Field

 

The following table sets forth our production, production prices and production costs for the Successor seven months ended December 31, 2018, and for the Predecessor five months ended May 31, 2018 and years ended December 31, 2017 and 2016 from the Barnett Shale, the Appalachian Basin and the San Juan Basin, which are the only fields during those years for which our estimated net proved reserves at December 31, 2018 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2018:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

Seven Months

 

 

Five Months

 

 

 

 

 

 

 

Ended

 

 

Ended

 

Year Ended December 31, 

 

December 31, 2018

 

    

May 31, 2018

    

2017

    

2016

Oil

 

  

 

 

 

  

 

 

  

 

 

  

Production (MBbls):

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

 

21

 

 

 

23

 

 

35

 

 

39

Appalachian Basin

 

290

 

 

 

209

 

 

541

 

 

611

San Juan Basin

 

44

 

 

 

29

 

 

74

 

 

75

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Bbl:

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

$

64.22

 

 

$

62.87

 

$

48.74

 

$

36.96

Appalachian Basin

$

62.22

 

 

$

61.63

 

$

47.29

 

$

39.59

San Juan Basin

$

56.31

 

 

$

53.03

 

$

38.20

 

$

31.01

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

  

 

 

 

  

 

 

  

 

 

  

Production (MMcf):

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

 

8,117

 

 

 

5,556

 

 

12,948

 

 

19,936

Appalachian Basin

 

5,159

 

 

 

3,458

 

 

11,465

 

 

12,097

San Juan Basin

 

2,960

 

 

 

2,205

 

 

5,336

 

 

3,751

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Mcf:

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

$

2.77

 

 

$

2.28

 

$

2.70

 

$

1.93

Appalachian Basin

$

2.78

 

 

$

2.44

 

$

2.45

 

$

1.70

San Juan Basin

$

2.50

 

 

$

2.24

 

$

2.82

 

$

2.37

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Liquids

 

  

 

 

 

  

 

 

  

 

 

  

Production (MBbls):

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

 

753

 

 

 

519

 

 

1,183

 

 

1,320

Appalachian Basin

 

26

 

 

 

29

 

 

43

 

 

59

San Juan Basin

 

303

 

 

 

204

 

 

390

 

 

405

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Bbl:

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

$

25.17

 

 

$

23.78

 

$

19.91

 

$

14.01

Appalachian Basin

$

20.00

 

 

$

28.79

 

$

15.53

 

$

14.12

San Juan Basin (1)

$

34.71

 

 

$

32.28

 

$

27.34

 

$

20.94

 

 

 

 

 

 

 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

  

 

 

 

  

 

 

  

 

 

  

Lease operating expenses per Mcfe (2)

 

  

 

 

 

  

 

 

  

 

 

  

Barnett Shale

$

1.33

 

 

$

1.34

 

$

1.25

 

$

0.95

Appalachian Basin

$

2.23

 

 

$

2.31

 

$

1.85

 

$

1.65

San Juan Basin

$

1.83

 

 

$

1.81

 

$

1.59

 

$

1.80


(1)Excludes a royalty adjustment of $5.0 million during the seven months ended December 31, 2018. Including this royalty adjustment, revenues from natural gas liquids would have been $3.05 per Bbl, for the seven months ended December 31, 2018. See Note 13 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

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(2)Excluding ad valorem taxes.

 

Our Drilling Activity

 

We intend to concentrate our drilling activity on low risk development drilling opportunities. The number and types of wells we drill will vary depending on the commodity price environment, the amount of funds we have available for drilling, the cost of each well, the size of the fractional working interests we acquire in each well, the estimated recoverable reserves attributable to each well and the accessibility to the well site.

 

The following table summarizes our approximate gross and net interest in development wells completed during the year ended December 31, 2018, 2017 and 2016, regardless of when drilling was initiated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled, quantities of reserves found or economic value.

 

 

 

 

 

 

 

 

Year Ended December 31, 

 

2018

    

2017

    

2016

Gross wells:

  

 

  

 

  

Productive

30.0

 

33.0

 

9.0

Dry

 —

 

 —

 

 —

Total

30.0

 

33.0

 

9.0

Net wells:

  

 

  

 

  

Productive

6.3

 

3.8

 

2.6

Dry

 —

 

 —

 

 —

Total

6.3

 

3.8

 

2.6

 

As of December 31, 2018, we were not participating in the drilling of any development wells.

 

We did not drill any exploratory wells during the seven months ended December 31, 2018. The Predecessor did not drill any exploratory wells during the five months ended May 31, 2018 or the years ended December 31, 2017 or 2016.

 

Well Operations

 

We have entered into operating agreements with EnerVest. Under these operating agreements, EnerVest acts as contract operator of the oil and natural gas wells and related gathering systems and production facilities in which we own an interest, provided that our interest entitles us to control the appointment of the operator of the well, gathering system or production facilities. As contract operator, EnerVest designs and manages the drilling and completion of our wells and manages the day to day operating and maintenance activities for our wells.

 

Under these operating agreements, EnerVest has established a joint account for each well in which we have an interest. We are required to pay our working interest share of amounts charged to the joint account. The joint account is charged with all direct expenses incurred in the operation of our wells and related gathering systems and production facilities. The determination of which direct expenses can be charged to the joint account and the manner of charging direct expenses to the joint account for our wells is done in accordance with the Council of Petroleum Accountants Societies (“COPAS”) model form of accounting procedure.

 

Under the COPAS model form, direct expenses include the costs of third party services performed on our properties and wells, as well as gathering and other equipment used on our properties. In addition, direct expenses include the allocable share of the cost of services performed on our properties and wells by EnerVest employees. The allocation of the cost of EnerVest employees who perform services on our properties is based on time sheets maintained by EnerVest’s employees. Direct expenses charged to the joint account also include an amount determined by EnerVest to be the fair rental value of facilities owned by EnerVest and used in the operation of our properties.

 

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Principal Customers, Marketing Arrangements and Delivery Commitments

 

The market for our oil, natural gas and natural gas liquids production depends on factors beyond our control, including the extent of domestic production and imports of oil, natural gas and natural gas liquids, the proximity and capacity of natural gas pipelines and other transportation facilities, the demand for oil, natural gas and natural gas liquids, the marketing of competitive fuels and the effect of state and federal regulation. The oil and natural gas industry also competes with other industries in supplying the energy and fuel requirements of industrial, commercial and individual consumers.

 

Our oil, natural gas and natural gas liquids production is sold to a variety of purchasers. The terms of sale under the majority of existing contracts are short–term, usually one year or less in duration. The prices received for oil, natural gas and natural gas liquids sales are generally tied to monthly or daily indices as quoted in industry publications.

 

During 2018, Energy Transfer Operating, L.P. accounted for 15.5% of consolidated oil, natural gas and natural gas liquids revenues. In 2017, Energy Transfer Partners, L.P. and EnLink Midstream Partners, L.P. accounted for 15.5% and 11.0%, respectively, of the Predecessor’s consolidated oil, natural gas and natural gas liquids revenues. In 2016, Energy Transfer Partners, L.P., EnLink Midstream Partners, L.P. and Ergon Oil Purchasing, Inc. accounted for 18.5%, 13.4% and 10.4%, respectively, of the Predecessor’s consolidated oil, natural gas and natural gas liquids revenues. We believe that the loss of a major customer would have a temporary effect on our revenues but that over time, we would be able to replace our major customers.

 

Information regarding our delivery commitments is contained in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations” contained herein.

 

Competition

 

The oil and natural gas industry is highly competitive. We encounter strong competition from other independent operators and from major oil and natural gas companies in acquiring properties, contracting for drilling equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. As a result, our competitors may be able to pay more for desirable leases, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.

 

We are also affected by competition for drilling rigs and the availability of related equipment. In the past, the oil and natural gas industry has experienced shortages of drilling rigs, equipment, pipe and personnel, which have delayed development drilling and other exploitation activities and have caused significant price increases. We are unable to predict when, or if, such shortages may occur or how they would affect our development and exploitation program.

 

Competition is also strong for attractive oil and natural gas producing properties, undeveloped leases and drilling rights, and there can be no assurances that we will be able to compete satisfactorily when attempting to make further acquisitions.

 

Seasonal Nature of Business

 

Seasonal weather conditions and lease stipulations can limit our drilling and producing activities and other operations primarily in certain areas of the Appalachian Basin, the San Juan Basin and Michigan. As a result, we generally perform the majority of our drilling in these areas during the summer and autumn months. In addition, the Monroe Field properties in Louisiana are subject to flooding. These seasonal anomalies can pose challenges for meeting our drilling objectives and increase competition for equipment, supplies and personnel during the drilling season, which could lead to shortages and increased costs or delay our operations. Generally demand for natural gas is higher in summer and winter months. In addition, certain natural gas users utilize natural gas storage facilities and purchase some of their anticipated winter natural gas requirements during off–peak months. This can also lessen seasonal demand fluctuations.

 

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Environmental, Health and Safety Matters and Regulation

 

Our operations are subject to stringent and complex federal, state and local laws and regulations that govern the health and safety aspects of our operations and protection of the environment, as well as the discharge of materials into the environment. These laws and regulations may, among other things:

 

require the acquisition of various permits before drilling commences;

 

require the installation of pollution control equipment in connection with operations and place other conditions on our operations;

 

place restrictions or regulations upon the use or disposal of the material utilized in our operations;

 

restrict the types, quantities and concentrations of various substances that can be released into the environment or used in connection with drilling, production and transportation activities;

 

limit or prohibit drilling activities on lands lying within wilderness, wetlands and other protected areas;

 

govern gathering, transportation and marketing of oil and natural gas and pipeline and facilities construction;

 

require remedial measures to mitigate pollution from former and ongoing operations, such as site restoration, pit closure and plugging of abandoned wells; and

 

require the expenditure of significant amounts in connection with worker health and safety.

 

These laws, rules and regulations may also restrict the rate of oil and natural gas production below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as waste handling, permitting, or cleanup for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry has recently been the subject of increased legislation and regulatory attention with respect to environmental matters. In early 2017, the US Environmental Protection Agency (the “EPA”) identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscal years 2018 and 2019; however, in 2019, the EPA proposed to transition its focus to significant public health and environmental problems without regard to sector. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental regulation may continue for the long term.

 

The following is a summary of some of the existing laws, rules and regulations to which our business operations are subject.

 

Solid and Hazardous Waste Handling

 

The federal Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous solid waste. Although oil and natural gas waste generally is exempt from regulations as hazardous waste under RCRA, we generate waste as a routine part of our operations that may be subject to RCRA. Although a substantial amount of the waste generated in our operations are regulated as non–hazardous solid waste rather than hazardous waste, there is no guarantee that the EPA or individual states will not adopt more stringent requirements for the handling of non–hazardous or exempt waste or categorize some non–hazardous or exempt waste as hazardous in the future. For example, following the filing of a lawsuit in the US District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the consent decree, the EPA is required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision

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of the regulations is not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations, the consent decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Any such change could result in an increase in our costs to manage and dispose of waste, which could have a material adverse effect on our results of operations and financial position.

 

Comprehensive Environmental Response, Compensation and Liability Act

 

The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”) imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as “hazardous substances.” These classes of persons, or so–called potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

 

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

 

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination, including groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

 

Clean Water Act

 

The Federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws impose restrictions and strict controls with respect to the discharge of pollutants, including discharges, spills and leaks of produced water and other oil and natural gas wastes, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. The Clean Water Act also prohibits the discharge of dredge and fill material in regulated waters, including wetlands, unless authorized by a permit issued by the US Army Corps of Engineers (the “Corps”). In June 2015, the EPA issued a final rule revising its definition of “waters of the United States.” Litigation surrounding this rule is ongoing and the rule was stayed nationwide by the US Sixth Circuit Court of Appeals in October 2015. In January 2018, the US Supreme Court ruled that the rule revising the definition of the term “waters of the United States” must first be reviewed in federal district courts, which resulted in a withdrawal of the Sixth Circuit stay. The EPA proposed to repeal the rule and, in January 2018, issued a final rule to delay its implementation until 2020 to allow time for the EPA to reconsider the definition. Subsequent litigation in the federal district courts has resulted in patchwork application of the rule in some states (e.g. Pennsylvania), but not others (e.g. Texas, Louisiana). In December 2018, the EPA and the Corps issued a proposed rule revising the definition of “waters of the United States” that would provide discrete categories of jurisdictional waters and tests for determining whether a particular waterbody meets any of those classifications. Several groups have already announced

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their intention to challenge the proposed rule. Federal and state regulatory agencies can impose administrative, civil and criminal penalties, as well as require remedial or mitigation measures, for non–compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. In the event of an unauthorized discharge of wastes, we may be liable for penalties and cleanup and response costs.

 

Safe Drinking Water Act and Hydraulic Fracturing

 

Hydraulic fracturing involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. Hydraulic fracturing activities are typically regulated by state oil and gas commissions or similar state agencies. Although the federal Safe Drinking Water Act (the “SDWA”) expressly excludes regulation of these fracturing activities (except for fracturing activities involving the use of diesel), several federal agencies have recently conducted investigations or asserted regulatory authority over certain aspects of the process due to public concerns raised regarding potential impacts of hydraulic fracturing on groundwater quality. These recent developments at the federal level, as well as at state, regional and local levels, could result in regulation of hydraulic fracturing becoming more stringent and costly. In December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business.

 

Legislation was introduced in prior sessions of Congress to provide for federal regulation of hydraulic fracturing by eliminating the current exemption in the SDWA, and, further, to require disclosure of the chemicals used in the fracturing process, but did not pass. Also, some states and local or regional regulatory bodies have adopted, or are considering adopting, regulations that could restrict or ban hydraulic fracturing in certain circumstances or that require disclosure of chemicals in the fracturing fluids. For example, New York has imposed a ban on hydraulic fracturing. Further, Pennsylvania has adopted a variety of regulations limiting how and where fracturing can be performed, and Wyoming and Texas have adopted legislation requiring drilling operators conducting hydraulic fracturing activities in that state to publicly disclose the chemicals used in the fracturing process. States have also considered or adopted other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; restrictions on access to, and usage of, water; and restrictions on the type of chemical additives that may be used in hydraulic fracturing operations. Further, the EPA has published guidance on hydraulic fracturing using diesel. The EPA has also published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants. The Bureau of Land Management (the “BLM”) published a final rule that established new or more stringent standards relating to hydraulic fracturing on federal and American Indian lands but, in late 2017, the BLM repealed this rule following years of litigation. The rescission of this rule is being challenged by several environmental groups and states in ongoing litigation.

 

State and federal regulatory agencies have also recently focused on a possible connection between the operation of injection wells used for oil and gas wastewater and an observed increase in minor seismic activity and tremors. When caused by human activity, such events are called induced seismicity. In a few instances, operators of injection wells in the vicinity of minor seismic events have reduced injection volumes or suspended operations, often voluntarily. Some state regulatory agencies have modified their regulations to account for induced seismicity. For example, the Texas Railroad Commission rules allow it to modify, suspend, or terminate a permit based on a determination that the permitted activity is likely to be contributing to seismic activity. Regulatory agencies are continuing to study possible linkage between injection activity and induced seismicity.

 

If new laws or regulations imposing significant restrictions or conditions on hydraulic fracturing activities are adopted in areas where we conduct business, we could incur substantial compliance costs and such requirements could adversely delay or restrict our ability to conduct fracturing activities on our assets.

 

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Oil Pollution Act

 

The primary federal law for oil spill liability is the Oil Pollution Act (“OPA”) which amends and augments oil spill provisions of the Clean Water Act and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening United States waters or adjoining shorelines. A liable “responsible party” includes the owner or operator of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge, or in the case of offshore facilities, the lessee or permittee of the area in which a discharging facility is located. OPA assigns joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist to the liability imposed by OPA, they are limited. In the event of an oil discharge or substantial threat of discharge, we may be liable for costs and damages.

 

Air Emissions

 

Our operations are subject to the federal Clean Air Act (“CAA”) and analogous state laws and local ordinances governing the control of emissions from sources of air pollution. The CAA and analogous state laws require new and modified sources of air pollutants to obtain permits prior to commencing construction. Major sources of air pollutants are subject to more stringent, federally imposed requirements including additional permits. Federal and state laws designed to control hazardous (or toxic) air pollutants, might require installation of additional controls. Administrative enforcement actions for failure to comply strictly with air pollution regulations or permits are generally resolved by payment of monetary fines and correction of any identified deficiencies. Alternatively, regulatory agencies could bring lawsuits for civil penalties or seek injunctive relief, requiring us to forego construction, modification or operation of certain air emission sources.

 

On April 17, 2012, the EPA issued final rules to subject oil and natural gas production, storage, processing and transmission operations to regulation under the New Source Performance Standards (“NSPS”) and the National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs under the CAA, and to impose new and amended requirements under both programs. The EPA rules include NSPS standards for completion of hydraulically fractured natural gas wells. Since January 1, 2015, operators have been required to capture the natural gas and make it available for use or sale, which can be done through the use of green completions. The standards are applicable to new hydraulically fractured wells and also existing wells that are refractured. Further, the finalized regulations also establish specific new requirements, effective in 2012, for emissions from compressors, controllers, dehydrators, storage tanks, natural gas processing plants and certain other equipment. These rules may require changes to our operations, including the installation of new equipment to control emissions. We continuously evaluate the effect of new rules on our business.

 

The EPA has adopted rules to regulate methane emissions, including, as of June 2016, from new and modified oil and gas production sources and natural gas processing and transmission sources, and has announced its intention to regulate methane emissions from existing oil and gas sources. However, in September 2018, the EPA, under the new administration, did propose amendments to the NSPS Subpart OOOOa standards that would relax the requirements implemented in June 2016. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is currently pending. The status of future regulation remains unclear but if adopted could require changes to our operations, including the installation of new emission control equipment. Simultaneously with the methane rules, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations. In late 2016, the BLM adopted a rule governing flaring and venting on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. Similar to the EPA rule, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of its November 2016 rule. This rule has been challenged in court by both California and New Mexico and litigation is ongoing. Additionally, the US House of Representatives passed a resolution under the Congressional Review Act disapproving the rules; however, the Senate action failed. If allowed to stand, these additional regulations on our air emissions are likely to result in increased compliance costs and additional operating restrictions on our business.

 

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National Environmental Policy Act

 

Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”) which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Depending on the mitigation strategies recommended in the Environmental Assessment or Environmental Impact Statement, we could incur added costs, which may be significant. Reviews and decisions under NEPA are also subject to protest or appeal, any or all of which may delay or halt projects. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands require governmental permits that are subject to the requirements of NEPA. This process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.

 

Climate Change Legislation

 

More stringent laws and regulations relating to climate change and greenhouse gases (“GHGs”) may be adopted in the future and could cause us to incur material expenses in complying with them. In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions; although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. Some states, regions and localities have adopted or have considered programs to address GHG emissions. In addition, both houses of Congress previously considered legislation to reduce emissions of greenhouse gases and many states have adopted or considered measures to establish GHG emissions reduction levels, often involving the planned development of GHG emission inventories and/or GHG cap and trade programs; this legislation was not passed.  Depending on the regulatory reach of new CAA legislation implementing regulations or new EPA and/or state, regional or local rules restricting the emission of GHGs, we could incur significant costs to control our emissions and comply with regulatory requirements. In addition, the EPA has adopted a mandatory GHG emissions reporting program which imposes reporting and monitoring requirements on various industries, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities. Compliance with these requirements has and is anticipated to require us to make investments in monitoring and recordkeeping equipment. We do not believe, however, that our compliance with applicable monitoring, recordkeeping and reporting requirements under the GHG reporting program will have a material adverse effect on our results of operations or financial position. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual basis.

 

The EPA began regulating methane emissions, including from new and modified oil and gas production sources and natural gas processing and transmission sources. In June 2016, the EPA published the NSPS Subpart OOOOa standards that require new, modified or reconstructed facilities in the oil and natural gas sector to reduce methane gas and volatile compound emissions. In September 2018, under the new administration, the EPA proposed amendments that would relax the requirements of the Subpart OOOOa standards. In addition, in April 2018, a coalition of states filed a lawsuit aiming to force the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is currently pending. Simultaneously with the methane rules for new and modified sources, the EPA adopted new rules governing the aggregating of multiple surface sites into a single-source of air quality permitting purposes, a change which could impact the applicability of permitting requirement to our operations and subject certain operations to additional regulatory requirements. We continuously evaluate the effect of these rules on our operations.

 

On November 18, 2016, the BLM published a final rule that was intended to reduce waste of natural gas from venting, flaring, and leaks during oil and natural gas production activities on onshore Federal and American Indian leases. Unlike the somewhat overlapping EPA regulations, which apply to new, modified and reconstructed sources, the BLM’s 2016 rule was drafted to address existing facilities, including a substantial number of existing wells that are likely to be marginal or low-producing, including leak detection and repair and other requirements regarding methane emissions. Similar to the EPA rule, in September 2018, the BLM issued a rule that relaxes or rescinds certain requirements of its November 2016 rule. California and New Mexico have challenged the rule in ongoing litigation.

 

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In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France. The resulting Paris Agreement calls for the parties to undertake “ambitious efforts” to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, on June 1, 2017, President Trump announced that the United States would withdraw from the Paris Agreement. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016, which would result in an effective exit date of November 2020. It is not clear what steps the Trump Administration plans to take to withdraw from the Paris Agreement, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

 

Because of the lack of any comprehensive legislative program addressing GHGs, there is a great deal of uncertainty as to how and when federal regulation of GHGs might take place. Moreover, the federal, regional, state and local regulatory initiatives also could adversely affect the marketability of the oil, natural gas and natural gas liquids we produce. The impact of such future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.

 

Endangered Species Act

 

The Endangered Species Act was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities that would harm the species or that would adversely affect that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We conduct operations on oil and natural gas leases that have species that are listed and species that could be listed as threatened or endangered under these laws. The US Fish and Wildlife Service designates the species’ protected habitat as part of the effort to protect the species. A protected habitat designation or the mere presence of threatened or endangered species could result in material restrictions to our use of the land and may materially delay or prohibit land access for oil and natural gas development. It also may adversely impact the value of the affected leases.

 

OSHA and Other Laws and Regulation

 

To the extent not preempted by other applicable laws, we are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes, where applicable. These laws and the implementing regulations strictly govern the protection of the health and safety of employees. The OSHA hazard communication standard, the EPA community right–to–know regulations under the Title III of CERCLA and similar state statutes, where applicable, require that we organize and/or disclose information about hazardous materials used or produced in our operations. We believe that we are in substantial compliance with these applicable requirements and with other OSHA and comparable state statute requirements.

 

We believe that we are in substantial compliance with all existing environmental laws and regulations applicable to our current operations and that our continued compliance with existing requirements will not have a material adverse impact on our financial condition and results of operations. We did not incur any material capital expenditures for remediation or pollution control activities for the years ended December 31, 2018, 2017 and 2016. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2019 or that will otherwise have a material impact on our financial position or results of operations in the future. However, we cannot assure you that the passage of more stringent laws and regulations in the future will not have a negative impact on our business activities, financial condition and results of operations.

 

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Other Regulation of the Oil and Natural Gas Industry

 

The oil and natural gas industry is extensively regulated by numerous federal, state, local and tribal authorities. Rules and regulations affecting the oil and natural gas industry are under constant review for amendment or expansion, which could increase the regulatory burden and the potential for financial sanctions for noncompliance. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other companies in the industry with similar types, quantities and locations of production.

 

Drilling and Production

 

Statutes, rules and regulations affecting exploration and production undergo constant review and often are amended, expanded and reinterpreted, making difficult the prediction of future costs or the impact of regulatory compliance attributable to new laws and statutes. The regulatory burden on the oil and natural gas industry increases the cost of doing business and, consequently, affects its profitability. Our drilling and production operations are subject to various types of regulation at the federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. Most states and some counties and municipalities in which we operate also regulate one or more of the following:

 

the location of wells;

 

the method of drilling, completing and operating wells;

 

the surface use and restoration of properties upon which wells are drilled;

 

the venting or flaring of natural gas;

 

the plugging and abandoning of wells;

 

notice to surface owners and other third parties; and

 

produced water and disposal of waste water, drilling fluids and other liquids and solids utilized or produced in the drilling and extraction process.

 

State and federal regulations are generally intended to prevent waste of oil and natural gas, protect correlative rights to produce oil and natural gas between owners in a common reservoir or formation, control the amount of oil and natural gas produced by assigning allowable rates of production and control contamination of the environment. Pipelines and natural gas plants operated by other companies that provide midstream services to us are also subject to the jurisdiction of various federal, state and local authorities, which can affect our operations. State laws also regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties and impose bonding requirements in order to drill and operate wells. Some states have taken up consideration of forced pooling. Other states rely on voluntary pooling of lands and leases.

 

States generally impose a production, ad valorem or severance tax with respect to the production and sale of oil and natural gas within their respective jurisdictions. States do not generally regulate wellhead prices or engage in other, similar direct economic regulation, but there can be no assurance they will not do so in the future.

 

We do not control the availability of transportation and processing facilities used in the marketing of our production. For example, we may have to shut–in a productive natural gas well because of a lack of available natural gas gathering or transportation facilities.

 

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If we conduct operations on federal, state or Indian oil and natural gas leases, these operations must comply with numerous regulatory restrictions, including various non–discrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by the BLM, Bureau of Ocean Energy Management, Bureau of Safety and Environmental Enforcement, Bureau of Indian Affairs, tribal or other appropriate federal, state and/or Indian tribal agencies.

 

The Mineral Leasing Act of 1920 (the “Mineral Act”) prohibits direct or indirect ownership of any interest in federal onshore oil and gas leases by a foreign citizen of a country that denies “similar or like privileges” to citizens of the United States. Such restrictions on citizens of a “non-reciprocal” country include ownership or holding or controlling stock in a corporation that holds a federal onshore oil and gas lease. If this restriction is violated, the corporation’s lease can be cancelled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non–reciprocal countries, there are presently no such designations in effect. It is possible that our stockholders may be citizens of foreign countries which at some time in the future might be determined to be non–reciprocal under the Mineral Act.

 

Federal Regulation of Oil, Natural Gas and Natural Gas Liquids, including Regulation of Transportation

 

The availability, terms and cost of transportation significantly affect sales of natural gas. The interstate transportation and sale for resale of natural gas are subject to federal regulation, including regulation of the terms, conditions and rates for interstate transportation, storage and various other matters, primarily by the Federal Energy Regulatory Commission (“FERC”). Federal and state regulations govern the price and terms for access to natural gas pipeline transportation. FERC’s regulations for interstate natural gas transmission in some circumstances may also affect the intrastate transportation of natural gas. FERC regulates the rates, terms and conditions applicable to the interstate transportation of natural gas by pipelines under the Natural Gas Act as well as under Section 311 of the Natural Gas Policy Act.

 

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

 

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

 

Sales of our oil and natural gas liquids are also affected by the availability, terms and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by the FERC under the Interstate Commerce Act (the “ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the (higher) filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various pipelines. It is too recent an event to determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

 

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

 

The pipelines used to gather and transport natural gas being produced by us are also subject to regulation by the US Department of Transportation (the “DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended (“NGPSA”), the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk–based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, the PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2015, the PHMSA issued proposed new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and that operators establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisions to gathering line regulations and liquids pipelines regulations are enacted by the PHMSA, we could incur significant expenses.

 

Transportation of our oil, natural gas liquids and purity components (ethane, propane, butane, iso–butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171‑180 (“HMR”), including Emergency Orders by the FRA and new regulations being proposed by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.

 

Although natural gas sales prices are currently unregulated, Congress historically has been active in the area of natural gas regulation. We cannot predict whether new legislation to regulate natural gas might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on the operations of the underlying properties. Sales of oil and natural gas liquids are not currently regulated and are made at market prices.

 

Exports of US Crude Oil Production and Natural Gas Production

 

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

 

Hydraulic Fracturing

 

Most of our oil and natural gas properties are subject to hydraulic fracturing to economically develop the properties. The hydraulic fracturing process is integral to our drilling and completion costs in these areas and typically represent up to 60% of the total drilling/completion costs per well.

 

We diligently review best practices and industry standards, and comply with all regulatory requirements in the protection of these potable water sources. Protective practices include, but are not limited to, setting multiple strings of

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protection pipe across the potable water sources and cementing these pipes from setting depth to surface, continuously monitoring the hydraulic fracturing process in real time, and disposing of all non–commercially produced fluids in certified disposal wells at depths below the potable water sources.

 

In compliance with laws enacted in various states, we will disclose hydraulic fracturing data to the appropriate chemical registry. These laws generally require disclosure for each chemical ingredient that is subject to the requirements of OSHA regulations, as well as the total volume of water used in the hydraulic fracturing treatment.

 

There have not been any material incidents, citations or suits related to our hydraulic fracturing activities involving violations of environmental laws and regulations.

 

Other Regulation

 

In addition to the regulation of oil and natural gas pipeline transportation rates, the oil and natural gas industry generally is subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to occupational safety, resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect upon our stockholders.

 

Insurance

 

In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. We currently have insurance policies that include coverage for control of well, general liability (includes sudden and accidental pollution), physical damage to our oil and gas natural properties, auto liability, worker’s compensation and employer’s liability, among other things.

 

Currently, we have general liability insurance coverage up to $1.0 million per occurrence, which includes sudden and accidental environmental liability coverage for the effects of pollution on third parties arising from our operations. Our insurance policies contain maximum policy limits and in most cases, deductibles that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain $100.0 million in excess liability coverage, which is in addition to and triggered if the general liability per occurrence limit is reached.

 

We do not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, we believe our general liability and excess liability insurance policies would cover third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.

 

We re–evaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. No assurance can be given that we will be able to maintain insurance in the future at rates that we consider reasonable, and we may elect to self–insure or maintain only catastrophic coverage for certain risks in the future.

 

Employees

 

As of December 31, 2018, we have five full–time employees, none of which are field personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be satisfactory.

 

Our operations are primarily carried out by EnerVest pursuant to the Services Agreement.

 

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Offices

 

We do not have any material owned or leased property (other than our interests in oil and gas properties). Under our Services Agreement, EnerVest provides us office space for our executive officers and other employees at EnerVest’s offices in Houston, Texas.

 

Available Information

 

Our annual reports on Form 10–K, quarterly reports on Form 10–Q, current reports on Form 8–K and amendments to those reports filed or furnished pursuant to Section 13(a) or 15(d) of the Exchange Act, are made available free of charge on our website at www.hvstog.com as soon as reasonably practicable after these reports have been electronically filed with, or furnished to, the SEC. Our website also includes our Code of Business Conduct and the charters of our audit committee and compensation committee. No information from our website is incorporated herein by reference.

 

ITEM 1A. RISK FACTORS

 

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

 

Risks Related to our Emergence from Bankruptcy

 

We recently emerged from bankruptcy, which may adversely affect our business and relationships.

 

It is possible that our having filed for bankruptcy and our recent emergence from bankruptcy may adversely affect our business and relationships with customers, vendors, royalty or working interest owners, contractors, employees or suppliers. Due to uncertainties, many risks exist, including the following:

 

·

key suppliers, vendors or other contract counterparties may terminate their relationships with us or require additional financial assurances or enhanced performance from us;

 

·

our ability to renew existing contracts and compete for new business may be adversely affected;

 

·

our ability to attract, motivate and/or retain key executives may be adversely affected; and

 

·

competitors may take business away from us, and our ability to attract and retain customers may be negatively impacted.

 

The occurrence of one or more of these events could have a material and adverse effect on our operations, financial condition and reputation. We cannot assure you that having been subject to bankruptcy protection will not adversely affect our operations in the future.

 

Our actual financial results after emergence from bankruptcy may not be comparable to our historical financial information as a result of the implementation of the Plan and the transactions contemplated thereby and our adoption of fresh start accounting.

 

In connection with the disclosure statement we filed with the Bankruptcy Court, and the hearing to consider confirmation of the Plan, we prepared projected financial information to demonstrate to the Bankruptcy Court the

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feasibility of the Plan and our ability to continue operations upon our emergence from bankruptcy. Those projections were prepared solely for the purpose of bankruptcy proceedings and have not been, and will not be, updated on an ongoing basis and should not be relied upon by investors. At the time they were prepared, the projections reflected numerous assumptions concerning our anticipated future performance with respect to prevailing and anticipated market and economic conditions that were and remain beyond our control and that may not materialize. Projections are inherently subject to substantial and numerous uncertainties and to a wide variety of significant business, economic and competitive risks and the assumptions underlying the projections and/or valuation estimates may prove to be wrong in material respects. Actual results may vary significantly from those contemplated by the projections. As a result, investors should not rely on these projections.

 

In addition, upon our emergence from bankruptcy, we adopted fresh start accounting. Accordingly, our future financial conditions and results of operations may not be comparable to the financial condition or results of operations reflected in the Predecessor’s historical financial statements. The lack of comparable historical financial information may discourage investors from purchasing our common stock.

 

Upon our emergence from bankruptcy, the composition of our board of directors changed significantly.

 

Pursuant to the Plan, the composition of our board of directors changed significantly. Upon emergence, our board of directors consists of five directors, only one of whom, our President and Chief Executive Officer, previously served on the board of directors of the Predecessor. The new directors have different backgrounds, experiences and perspectives from those individuals who previously served on our board of directors and, thus, may have different views on the issues that will determine our future. As a result, the future strategy and our plans may differ materially from those of the past.

 

Risks Related to our Business

 

Oil, natural gas and natural gas liquids prices are highly volatile and have declined significantly in recent years. Depressed prices can significantly and adversely affect our business, financial condition, results of operations and cash flows from operations.

 

Our revenue, profitability, cash flow and future rate of growth depend upon the prices for oil, natural gas and natural gas liquids. Prices for these commodities have been depressed when compared with historical prices prior to the second half of 2014, and the prices we receive for our production are volatile. For example, oil and natural gas commodity prices declined significantly in the fourth quarter of 2018, with the posted price for West Texas Intermediate oil falling to a low of $44.48 per barrel in December 2018 as compared to the quarter-high of $76.40 in October 2018. Prices for oil, natural gas and natural gas liquids may fluctuate widely in response to relatively minor changes in supply and demand, market uncertainty and a variety of additional factors that are beyond our control, such as:

 

the domestic and foreign supply of and demand for oil, natural gas and natural gas liquids;

 

the amount of added production from development of unconventional natural gas reserves;

 

the price and quantity of foreign imports of oil, natural gas and natural gas liquids;

 

the level of consumer product demand;

 

weather conditions;

 

the value of the US dollar relative to the currencies of other countries;

 

market uncertainty and overall domestic and global economic conditions;

 

political and economic conditions and events in foreign oil and natural gas producing countries, including embargoes, continued hostilities in the Middle East and other sustained military campaigns, conditions in South America, China and Russia, and acts of terrorism or sabotage;

 

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the increasing exports of oil produced in the US and natural gas produced in the US from LNG liquefaction facilities;

 

the ability of members of the Organization of Petroleum Exporting Countries to agree to and maintain oil price and production controls;

 

technological advances affecting energy production and consumption;

 

domestic and foreign governmental regulations and taxation;

 

the impact of energy conservation efforts and the increasing use of renewable sources of energy such as wind energy and solar photovoltaic energy;

 

the capacity of the US and international refiners to utilize US supplies of oil, natural gas and natural gas liquids;

 

the proximity and capacity of natural gas pipelines and other transportation facilities to our production; and

 

the price and availability of alternative fuels.

 

A drop in commodity prices can significantly affect our financial results and cash flows and impede our growth. The ways in which such price decreases could have a material negative effect on our business include:

 

a significant decrease in the number of wells we drill on our acreage, thereby reducing our production and cash flows;

 

a reduction in cash flow, which would decrease funds available to repay current or future indebtedness or for capital expenditures employed to replace reserves and maintain or increase production;

 

access to sources of capital, such as equity or long-term debt markets, could be severely limited or unavailable; and

 

a reduction in the borrowing base of our credit facility.

 

In addition, changes in prices have a significant impact on the value of our reserves, and lower prices may reduce the amount of oil, natural gas or natural gas liquids that we can economically produce. This may result in our having to make substantial downward adjustments to our estimated proved reserves. If this occurs, or if our estimates of development costs increase, production data factors change or drilling results deteriorate, accounting rules may require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties for impairments. An impairment charge could have a material adverse effect on our results of operations in the period in which it is recorded. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets. For example, we expect to record an impairment charge related to our pending sale of our properties in the San Juan Basin.

 

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

 

The operating and financial restrictions and covenants in our financing agreements may restrict our ability to finance operations or capital needs or to engage, expand or pursue our business activities. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Liquidity and Capital Resources.” Our future ability to comply with these restrictions and covenants is uncertain and will be affected by the levels of cash flow from our operations and other events or circumstances beyond our control. If market or other economic conditions deteriorate, our ability to comply with these covenants may be impaired. If we violate any provisions of such financing agreements that are not

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cured or waived within the appropriate time periods provided therein, a significant portion of our indebtedness may become immediately due and payable and our lenders’ commitment to make further loans to us may terminate. We might not have, or be able to obtain, sufficient funds to make these accelerated payments. In addition, our obligations under our credit facility are secured by substantially all of our assets, and if we are unable to repay our indebtedness under our credit facility, the lenders could seek to foreclose on our assets.

 

The terms and conditions governing our indebtedness:

 

depending on the amount of outstanding indebtedness, could require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate;

 

increase our vulnerability to economic downturns and adverse developments in our business;

 

limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

 

place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;

 

place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness;

 

make it more difficult for us to satisfy our obligations under our debt and increase the risk that we may default on our debt obligations; and

 

limit management’s discretion in operating our business.

 

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

 

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

 

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

 

We have historically funded our operations, including our operating and capital expenditures, our debt service obligations and our acquisitions primarily through cash generated from operations, amounts available under our credit

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

 

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

 

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

 

refinancing or restructuring debt;

 

selling assets;

 

reducing or delaying capital investments;

 

seeking to raise additional capital;

 

liquidating all or a portion of our hedge portfolio;

 

seeking additional partners to develop our assets;

 

reducing our planned capital program;

 

continuing to take, and potentially increasing, our cost saving measures to reduce costs, including renegotiation contracts with contractors, suppliers and service providers, reducing the number of staff and contractors and deferring and eliminating discretionary costs; or

 

revising or delaying our other strategic plans.

 

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

 

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

 

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

 

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

 

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

 

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

 

Our inability to finance the development of our properties, future oil and natural gas price declines and other factors may result in additional write-downs of our asset carrying values.

 

Accounting rules require us to write down, as a non–cash charge to earnings, the carrying value of our oil and natural gas properties in the event we have impairments. We are required to perform impairment tests on our assets periodically and whenever events or changes in circumstances warrant a review of our assets. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our assets, the carrying value may not be recoverable and therefore requires a write–down. An impairment charge could have a material adverse effect on our results of operations in the period in which it is recorded. During the seven months ended December 31, 2018, we recorded impairment charges of approximately $3.1 million, which were related to properties located in Central Texas and Karnes County, Texas that were sold during August 2018. We expect to record an impairment charge in connection with the sale of our properties in the San Juan Basin during the first quarter of 2019. We may incur additional impairment charges in the future, particularly if commodity prices significantly decrease.

 

Proved undeveloped drilling locations are susceptible to uncertainties that could materially alter the occurrence or timing of their drilling and result in changes to the amount of our proved undeveloped reserves.

 

Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, construction of infrastructure, inclement weather, regulatory changes and approvals, oil and natural gas prices, costs, drilling results and the availability of water. We cannot be certain in advance of drilling and testing whether any particular drilling location will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. As a result, we do not know with certainty if these locations we have identified will ever be drilled or if we will be able to produce oil or natural gas from these or any other potential drilling locations. As such, our actual drilling activities may materially differ from those presently identified, which could adversely affect our business.

 

The recovery of PUDs requires significant capital expenditures and successful drilling operations. We can provide no assurances that we will have the ability to finance these future expenditures, whether development will occur as scheduled or that the results of such development will be as estimated. In addition, delays in the development could force us to reclassify certain of our proved reserves as unproved reserves. Further, the decision of the operators to develop the PUDs

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attributable to our properties that EnerVest does not operate will be subject to the business plans and constraints of the operators of these properties, and be beyond our control.

 

We depend on EnerVest to provide us services necessary to operate our business and substantially all of our properties. If EnerVest were unable or unwilling to provide these services, it would result in disruption in our business which could have an adverse effect on our ability to service our debt obligations.

 

Under the Services Agreement, EnerVest provides services to us such as accounting, human resources, office space, digital infrastructure and other administrative services. If EnerVest were to become unable or unwilling to provide these services, we would need to develop these services internally or arrange for the services from another service provider. Developing the capabilities internally or by retaining another service provider could have an adverse effect on our business, and the services, when developed or retained, may not be of the same quality as provided to us by EnerVest.

 

EnerVest also operates a substantial amount of our properties pursuant to the Services Agreement. As of December 31, 2018, EnerVest operated oil and natural gas properties representing 92% of our proved oil and gas reserves and also had an economic interest in some of our properties. However, on February 1, 2019, operatorship of certain properties was transferred to a third party as a result of an EnerVest transaction. As a result, EnerVest now operates oil and gas properties representing approximately 53% of our proved oil and gas reserves. Our limited control over the operations related to our properties operated by EnerVest is set forth in our Services Agreement. The success and timing of drilling and development activities on the properties operated by EnerVest depends on a number of factors that will be largely outside of our control.

 

Prior to the Restructuring, EnerVest and its affiliates had a significant economic interest in the Predecessor through its 71.25% ownership of the Predecessor’s general partner which, in turn, owned a 2% general partnership interest in the Predecessor and all of its incentive distribution rights. In connection with the Restructuring, the Predecessor’s general partner was dissolved and EnerVest no longer has an economic interest in us. As a result, our interests may not be aligned or could be in conflict with EnerVest’s interests.

 

We currently own interests in oil and natural gas properties in which partnerships managed by EnerVest also own an interest. If the EnerVest partnerships elect to sell their interest in these properties, we would own a minority interest in the properties, and EnerVest may lose the ability to operate the properties.

 

We own interests in oil and natural gas properties in which partnerships managed by EnerVest also own interests. These properties are primarily in the Barnett Shale and Appalachian Basin, and these properties represented approximately 57% of our estimated net proved reserves as of December 31, 2018. If the EnerVest partnerships were to sell their interest in those properties in which we own less than a majority working interest to an entity not affiliated with EnerVest, our working interest would not be large enough that we could control the selection of the operator and EnerVest may lose the ability to operate the properties on our behalf. Loss of operations would mean that EnerVest would no longer control decisions regarding the development and production of those properties, and any replacement operator could make decisions regarding development or production activities that make it difficult to implement our strategy.

 

Our hedging transactions may limit our gains, result in financial losses or could reduce our net income, which may adversely affect our ability to service our debt obligations and expose us to counterparty credit risk.

 

We enter into derivative contracts from time to time to manage our exposure to fluctuations in oil, natural gas and natural gas liquids prices, to achieve more predictable cash flows and to reduce our exposure to fluctuations in the prices of oil, natural gas and natural gas liquids. The prices at which we hedge our production in the future will be dependent upon commodity prices at the time we enter into these transactions, which may be substantially higher or lower than current oil and natural gas prices. Accordingly, these derivative contracts limit our potential gains if prices rise above the fixed prices established by the derivative contracts. These derivative contracts may also expose us to other risks of financial losses; for example, if our production is less than we anticipated at the time we entered into the derivatives contract, we might be forced to satisfy all or a portion of our hedging obligations without the benefit of the cash flows from our sale of the underlying physical commodity, resulting in a substantial diminution of our liquidity.

 

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During periods of falling commodity prices, our derivative contracts expose us to risk of financial loss if the counterparty to the derivative contract fails to perform its obligations under the derivative contract (e.g., our counterparty fails to perform its obligation to make payments to us under the derivative contract when the market (floating) price under such derivative contract falls below the specified fixed price). To mitigate counterparty credit risk, we conduct our hedging activities with financial institutions who are lenders under our credit facility. Disruptions in the financial markets could lead to sudden changes in a counterparty’s liquidity, which could impair their ability to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions. If the creditworthiness of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

 

Our policy has been to hedge a significant portion of our near–term estimated production. However, we are not under an obligation to hedge a specific portion of our production except that our credit facility requires us to hedge 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. As of December 31, 2018, we have commodity contracts covering approximately 68% of our estimated production attributable to our net proved reserves from January 2019 through December 2020. Accordingly, our price hedging strategy may not protect us from significant declines in oil and natural gas prices received for our future production. Conversely, our hedging strategy may limit our ability to realize cash flows from commodity price increases.

 

Our limited ability to hedge our natural gas liquids production could adversely impact our net cash provided by operating activities and results of operations.

 

A liquid, readily available and commercially viable market for hedging natural gas liquids has not developed in the same way that exists for oil and natural gas. The current direct natural gas liquids hedging market is constrained in terms of price, volume, duration and number of counterparties, which may limit our ability to hedge our natural gas liquids production effectively. As a result, our net cash provided by operating activities and results of operations could be adversely impacted by fluctuations in the market prices for natural gas liquids.

 

The adoption of derivatives legislation and regulations related to derivative contracts could have an adverse impact on our ability to hedge risks associated with our business.

 

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the OTC market. Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas and the scope of relevant definitions and/or exemptions still remain to be finalized.

 

In one of its rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC issued on December 5, 2016, a re-proposed rule imposing position limits for certain futures and option contracts in various commodities (including crude oil and natural gas) and for swaps that are their economic equivalents. Under the proposed rules on position limits, certain types of hedging transactions are exempt from these limits on the size of positions that may be held, provided that such hedging transactions satisfy the CFTC’s requirements for certain enumerated “bona fide hedging” transactions or positions. A final rule has not yet been issued. Similarly, on December 2, 2016, the CFTC has re-issued a proposed rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, but the CFTC has not yet issued a final rule.

 

The CFTC issued a final rule on margin requirements for uncleared swap transactions on January 6, 2016, which includes an exemption from any requirement to post margin to secure uncleared swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exemption from the otherwise applicable mandatory obligation to clear certain types of swap transactions through a derivatives clearing organization and to trade such swaps on a regulated exchange, which exemption applies to swap transactions entered into by commercial end-users in order to hedge commercial risks affecting their

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business. The mandatory clearing requirement currently applies only to certain interest rate swaps and credit default swaps, but the CFTC could act to impose mandatory clearing requirements for other types of swap transactions. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations.

 

All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business. While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, depending on our ability to satisfy the CFTC’s requirements for a commercial end-user using swaps to hedge or mitigate our commercial risks, these rules and regulations may require us to comply with position limits and with certain clearing and trade-execution requirements in connection with our financial derivative activities. When a final rule on capital requirements for swap dealers is issued, the Dodd-Frank Act may require our current swap dealer counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which capital requirements rule could increase the costs to us of future financial derivatives transactions. The Volcker Rule provisions of the Dodd-Frank Act may also require our current bank counterparties that engage in financial derivative transactions to spin off some of their derivatives activities to separate entities, which separate entities may not be as creditworthy as the current bank counterparties. Under such rules, other bank counterparties may cease their current business as hedge providers. These changes could reduce the liquidity of the financial derivatives markets thereby reducing the ability of entities like us, as commercial end-users, to have access to financial derivatives to hedge or mitigate our exposure to commodity price volatility.

 

As a result, the Dodd-Frank Act and any new regulations issued thereunder could significantly increase the cost of derivative contracts (including through requirements to post cash collateral), which could adversely affect our capital available for other commercial operations purposes, materially alter the terms of future swaps relative to the terms of our existing bilaterally negotiated financial derivative contracts and reduce the availability of derivatives to protect against commercial risks we encounter.

 

If we reduce our use of derivative contracts as a result of the new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil, natural gas and natural gas liquids. Our revenues could therefore be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial condition, results of operations or cash flows.

 

Should we fail to comply with all applicable statutes, rules, regulations and orders administered by the CFTC or FERC, we could be subject to substantial penalties and fines.

 

Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the Natural Gas Act (“NGA”), including the ability to impose penalties of up to $1 million per day for each violation and disgorgement of profits associated with any violation. While our operations have not been regulated by FERC as a natural gas company under the NGA, FERC has adopted regulations that may subject certain of our otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also must comply with the anti-market manipulation rules enforced by FERC under the NGA. Under the Commodity Exchange Act (as amended by the Dodd-Frank Act) and regulations promulgated thereunder by the CFTC, the CFTC has also adopted anti-market manipulation, fraud and market disruption rules relating to the prices of commodities, futures contracts, options on futures, and swaps. Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, or the CFTC from time to time. Failure to comply with those statutes, regulations, rules and orders could subject us to civil penalty liability.

 

The distressed financial conditions of customers could have an adverse impact on us in the event these customers are unable to pay us for the products or services we provide.

 

Some of our customers may experience, in the future, severe financial problems that have had or may have a significant impact on their creditworthiness. We cannot provide assurance that one or more of our financially distressed customers

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will not default on their obligations to us or that such a default or defaults will not have a material adverse effect on our business, financial position, future results of operations or future cash flows. Furthermore, the bankruptcy of one or more of our customers, or some other similar proceeding or liquidity constraint, might make it unlikely that we would be able to collect all or a significant portion of amounts owed by the distressed entity or entities. In addition, such events might force such customers to reduce or curtail their future use of our products and services, which could have a material adverse effect on our results of operations and financial condition.

 

We may be subject to risks in connection with divestitures.

In 2018, we completed divestitures of several of our assets and we have additional divestitures pending, as discussed in “Item 1. Business—Overview—Recent Developments,” in accordance with our ongoing review of our asset base in order to maximize shareholder value. Various factors could materially affect our ability to dispose of such assets, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets on terms we deem acceptable. Though we continue to evaluate various options for the divestiture of such assets, there can be no assurance that this evaluation will result in any specific action.

Sellers often retain certain liabilities or agree to indemnify buyers for certain matters related to the sold assets. The magnitude of any such retained liability or of the indemnification obligation is difficult to quantify at the time of the transaction and ultimately could be material. Also, as is typical in divestiture transactions, third parties may be unwilling to release us from guarantees or other credit support provided prior to the sale of the divested assets. As a result, after a divestiture, we may remain secondarily liable for the obligations guaranteed or supported to the extent that the buyer of the assets fails to perform these obligations.

Unless we replace the reserves we produce, our revenues and production will decline, which would adversely affect our cash flows from operations and our ability to service our debt obligations.

 

Producing reservoirs are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our decline rate may change when we drill additional wells, make acquisitions or under other circumstances. Our future cash flows and income are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs, which would adversely affect our business, financial condition and results of operations. Factors that may hinder our ability to acquire additional reserves include competition, access to capital, prevailing oil, natural gas and natural gas liquids prices and the number and attractiveness of properties for sale.

 

Our estimated reserve quantities and future production rates are based on many assumptions that may prove to be inaccurate. Any material inaccuracies in these reserve estimates or the underlying assumptions will materially affect the quantities and present value of our reserves.

 

Numerous uncertainties are inherent in estimating quantities of our reserves. Our estimates of our net proved reserve quantities are based upon reports from Cawley Gillespie and Wright, independent petroleum engineering firms used by us. The process of estimating oil, natural gas and natural gas liquids reserves is complex, requiring significant decisions and assumptions in the evaluation of available geological, engineering and economic data for each reservoir, and these reports rely upon various assumptions, including assumptions regarding future oil, natural gas and natural gas liquids prices, production levels, and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may prove to be inaccurate. Over time, we may make material changes to reserve estimates taking into account the results of actual drilling and production. Any significant variance in our assumptions and actual results could greatly affect our estimates of reserves, the economically recoverable quantities of oil, natural gas and natural gas liquids attributable to any particular group of properties, the classifications of reserves based on risk of recovery, and estimates of the future net cash flows. In addition, our wells are characterized by low production rates per well. As a result, changes in future production costs assumptions could have a significant effect on our proved reserve quantities.

 

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The standardized measure of discounted future net cash flows of our estimated net proved reserves is not necessarily the same as the current market value of our estimated net proved reserves. We base the discounted future net cash flows from our estimated net proved reserves on average prices for the 12 months preceding the date of the estimate. Actual prices received for production and actual costs of such production will be different than these assumptions, perhaps materially.

 

The timing of both our production and our incurrence of expenses in connection with the development and production of our properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% discount factor we use when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. Any material inaccuracy in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves which could adversely affect our business, results of operations and financial condition.

 

Our future development operations may require substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our production and reserves.

 

The oil and natural gas industry is capital intensive. We may make substantial capital expenditures in our business in the future for the development, production and acquisition of reserves. As part of our exploration and development operations, we have expanded, and expect to further expand, the application of horizontal drilling and multi-stage hydraulic fracture stimulation techniques. The utilization of these techniques requires substantially greater capital expenditures as compared to the drilling of a vertical well, sometimes more than three times the cost. The incremental capital expenditures are the result of greater measured depths and additional hydraulic fracture stages in horizontal wellbores.

 

We intend to finance our future capital expenditures primarily with cash flows from operations and borrowings under our credit facility. In the future, we may also finance such expenditures through the issuance of debt and equity securities. The incurrence of debt will require that a portion of our cash flows from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flows to fund working capital, capital expenditures and acquisitions. Our cash flows from operations and access to capital are subject to a number of variables, including:

 

the estimated quantities of our reserves;

 

the amount of oil, natural gas and natural gas liquids we produce from existing wells;

 

the prices at which we sell our production; and

 

our ability to acquire, locate and produce new reserves.

 

If our revenues or the borrowing base under our credit facility decrease as a result of lower commodity prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. Our credit facility may restrict our ability to obtain new financing. If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If cash generated by operations or available under our credit facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our prospects, which in turn could lead to a possible decline in our reserves and production, and could adversely affect our business, results of operation and financial conditions. In addition, we may lose opportunities to acquire oil and natural gas properties and businesses.

 

We rely on development drilling to assist in maintaining our levels of production. If our development drilling is unsuccessful, our cash available for servicing our debt obligations and financial condition will be adversely affected.

 

Part of our business strategy has focused on maintaining or minimizing the decline in production levels by drilling development wells. Although we were successful in development drilling in the past, we cannot assure you that we will continue to maintain production levels through development drilling, particularly in the current commodity price

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environment. Our drilling involves numerous risks, including the risk that we will not encounter commercially productive oil or natural gas reservoirs. We must incur significant expenditures to drill and complete wells. Additionally, seismic technology does not allow us to know conclusively, prior to drilling a well, that oil or natural gas is present or economically producible. The costs of drilling and completing wells are often uncertain, and it is possible that we will make substantial expenditures on development drilling and not discover reserves in commercially viable quantities. These expenditures will reduce cash available for servicing our debt obligations.

 

Our drilling operations may be curtailed, delayed or cancelled as a result of a variety of factors, including:

 

unexpected drilling conditions;

 

facility or equipment failure or accidents;

 

shortages or delays in the availability of drilling rigs and equipment;

 

adverse weather conditions;

 

compliance with environmental and governmental requirements;

 

title problems;

 

unusual or unexpected geological formations;

 

pipeline ruptures;

 

fires, blowouts, craterings and explosions; and

 

uncontrollable flows of oil or natural gas or well fluids.

 

Our business strategy involves the use of the latest available horizontal drilling, completion and production technology, which involve risks and uncertainties in their application.

 

Our operations involve the use of the latest horizontal drilling, completion and production technologies, as developed by us and our service providers, in an effort to improve efficiencies in recovery of hydrocarbons. Use of these new technologies may not prove successful and could result in significant cost overruns or delays or reduction in production, and in extreme cases, the abandonment of a well. The difficulties we face drilling horizontal wells include:

 

landing our wellbore in the desired drilling zone;

 

staying in the desired drilling zone while drilling horizontally through the formation;

 

running our production casing the entire length of the wellbore; and

 

running tools and other equipment consistently through the horizontal wellbore.

 

Difficulties that we face while completing our wells include the following:

 

designing and executing the optimum fracture stimulation program for a specific target zone;

 

running tools the entire length of the wellbore during completion operations; and

 

cleaning out the wellbore after completion of the fracture stimulation.

 

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In addition, certain of the new techniques we are adopting may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the application of technology developed in drilling, completing and producing in one productive formation may not be successful in other prospective formations with little or no horizontal drilling history. If our use of the latest technologies does not prove successful, our drilling and production results may be less than anticipated or we may experience cost overruns, delays in obtaining production or abandonment of a well. As a result, the return on our investment will be adversely affected, we could incur material write-downs of unevaluated properties or undeveloped reserves and the value of our undeveloped acreage and reserves could decline in the future.

 

We could experience periods of higher costs if oil and natural gas prices rise or as drilling activity otherwise increases in our area of operations. Higher costs could reduce our profitability, cash flow and ability to pursue our drilling program as planned.

 

Historically, our capital and operating costs typically rise during periods of sustained increasing oil, natural gas and natural gas liquids prices. These cost increases result from a variety of factors beyond our control as drilling activity increases, such as increases in the cost of electricity, tubular goods, water, sand and other disposable materials used in fracture stimulation and other raw materials that we and our vendors rely upon; and the cost of services and labor especially those required in horizontal drilling and completion. Since late 2014, oil and natural gas prices declined substantially resulting in decreased levels of drilling activity in the US oil and natural gas industry, including in our area of operations. This led to significantly lower costs of some drilling and completion equipment, services, materials and supplies. As commodity prices rise or stabilize or drilling activity otherwise increases in our area of operations, these lower cost levels may not be sustainable over long periods. As a result, such costs may rise, thereby negatively impacting our profitability, cash flow and causing us to possibly reconfigure or reduce our drilling program. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative risk management activitie