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, 2019

 

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 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  ☐

 

The aggregate market value of voting and non-voting common equity held by non-affiliates of the registrants was approximately $40.7 million as of June 28, 2019 (based on the last sale price of such common stock as reported on the OTCQX U.S. Premier Marketplace).

 

As of April 8, 2020, the registrant had 10,173,707 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, 2019, are incorporated by reference into Part III of this Annual Report on Form 10-K.

 

 

 

 

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Table of Contents

Table of Contents

 

 

 

 

 

 

 

    

PART I

    

 

 

 

 

 

 

Item 1. 

 

Business

 

7

Item 1A. 

 

Risk Factors

 

29

Item 1B. 

 

Unresolved Staff Comments

 

43

Item 2. 

 

Properties

 

43

Item 3. 

 

Legal Proceedings

 

43

Item 4. 

 

Mine Safety Disclosures

 

43

 

 

 

 

 

 

 

PART II

 

43

 

 

 

 

 

Item 5. 

 

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

 

43

Item 6. 

 

Selected Financial Data

 

44

Item 7. 

 

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

 

44

Item 7A. 

 

Quantitative and Qualitative Disclosures About Market Risk

 

58

Item 8. 

 

Financial Statements and Supplementary Data

 

59

Item 9. 

 

Changes in and Disagreements With Accountants on Accounting and Financial Disclosure

 

104

Item 9A. 

 

Controls and Procedures

 

104

Item 9B. 

 

Other Information

 

104

 

 

 

 

 

 

 

PART III

 

105

 

 

 

 

 

Item 10. 

 

Directors, Executive Officers and Corporate Governance

 

105

Item 11. 

 

Executive Compensation

 

105

Item 12. 

 

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

 

105

Item 13. 

 

Certain Relationships and Related Transactions, and Director Independence

 

105

Item 14. 

 

Principal Accounting Fees and Services

 

105

 

 

 

 

 

 

 

PART IV

 

106

 

 

 

 

 

Item 15. 

 

Exhibits, Financial Statement Schedules

 

106

Item 16. 

 

Form 10-K Summary

 

109

 

 

 

 

 

Signatures 

 

110

 

 

 

 

 

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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, 2019, our oil and natural gas properties are located in the Appalachian Basin (which includes the Utica Shale), Michigan, the Barnett Shale, and the Permian Basin. As of December 31, 2019, we had estimated net proved reserves of 155.8 Bcfe and a standardized measure of $106.9 million. Of our total net proved reserves, 100% are proved developed, 76% are natural gas and 88% are operated.

 

We continue to review strategic alternatives in order to maximize shareholder value. We divested significant assets during 2019 and are also actively considering the potential divestiture of all of our remaining assets as well as a potential sale or merger of the Company. In addition, we are reviewing options to reduce our overall cost structure to more closely align with our asset base. There can be no assurance that we will be successful in the near-term in divesting our remaining assets or merging the Company and the outcome of our cost-cutting efforts is still being developed. 

 

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 stakeholders which 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”). 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’ plan of reorganization (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 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.

 

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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

 

Global Industry Downturn

 

In late March 2020, NYMEX WTI crude oil prices and Henry Hub natural gas prices declined significantly, trading as low as $19.27 per barrel and $1.52 per MMBtu, respectively, as a result of market concerns about the ability of the Organization of Petroleum Exporting Countries (“OPEC”) and Russia to agree on implementing further production cuts in response to weaker worldwide demand, and to the outbreak of a highly transmissible and pathogenic coronavirus (“COVID-19”). We intend to tailor our operating plan and strategy, including asset base reviews and divestitures, in view of the existing and expected pricing environment.

 

Our Operating Plan and Strategy

 

Our overall operating plan includes regular reviews of our asset base and cost structure to maximize cash flow. We continue to review strategic alternatives in order to maximize shareholder value. We are actively considering the potential divestiture of all of our remaining assets as well as a potential sale or merger of the Company. There can be no assurance that any such evaluations or reviews will result in one or more transactions or other strategic change or outcome.

 

We also focus our efforts on 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 workover and drilling operations.

 

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 2020.

 

Prices for oil, natural gas and natural gas liquids have significantly declined since December 31, 2019. These lower prices could affect our business in numerous ways, including, a negative impact on the Company’s revenues, earnings and cash flows in 2020 and future years and a decrease in proved reserves and possible impairments of the Company’s remaining oil and natural gas properties.

 

Divestitures

 

During January 2019, we sold all of our 4.2 million shares of common stock of Magnolia Oil & Gas Corporation (NYSE: MGY) (“Magnolia”) for net proceeds of $51.7 million.

 

In January 2019, we closed on the sale of certain oil and natural gas properties in the Mid-Continent area to a third party for total consideration of $1.8 million, net of purchase price adjustments. We did not record a gain, loss or impairment related to this sale.

 

In April 2019, we closed on the sale of all of our (i) oil and natural 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 $36.8 million, net of purchase price adjustments, of which $0.3 million is receivable related to the final purchase price settlement and is included in “Accounts receivable – other” on the consolidated balance sheets. We expect to receive these proceeds in 2020. We recognized impairment expense of $25.4 million during the year ended December 31, 2019 related to this sale.

 

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During the second quarter of 2019, we closed on the sale of certain oil and natural gas properties in the Mid-Continent area to a third party for total consideration of $2.2 million, net of purchase price adjustments, which included $0.9 million of preferential rights to purchase that were exercised by other working interest owners. We recognized impairment expense of $1.8 million during the year ended December 31, 2019 related to this sale.

 

In September and December of 2019, we closed on the sale of substantially all of its oil and natural gas properties in the Barnett Shale for total consideration of $68.4 million, net of purchase price adjustments. The sale of the remaining oil and natural gas properties in the Barnett Shale are expected to close during the first half of 2020 for total consideration of $0.1 million subject to customary purchase price adjustments.  We recognized impairment expense of $78.1 million during the year ended December 31, 2019 related to this sale. As of December 31, 2019, the remaining oil and natural gas properties in the Barnett Shale were classified as held for sale; $0.1 million of the assets held for sale and less than $0.1 million of the ARO classified as liabilities held for sale on the consolidated balance sheets were attributable to these oil and natural gas properties not yet sold.

 

In September 2019, we closed on the sale of certain oil and natural gas properties in the Mid-Continent area to a third party for total consideration of $4.9 million, net of purchase price adjustments, of which $0.4 million is payable related to the final purchase price settlement and is included in “Accounts payable and accrued liabilities” on the consolidated balance sheets. We recognized a gain of $0.2 million during the year ended December 31, 2019 related to this sale.

   

In November 2019, we closed on the sale of all of its oil and natural gas properties in the Monroe Field in Northern Louisiana for total consideration due to the buyer of less than $0.1 million, net of purchase price adjustments, of which $0.2 million is receivable related to the final purchase price settlement and is included in “Accounts receivable – other” on the consolidated balance sheets. We expect to receive these proceeds in 2020. We recognized impairment expense of $2.1 million during the year ended December 31, 2019 related to this sale.

   

In December 2019, we closed on the sale of substantially all of its oil and natural gas properties in the Permian Basin for total consideration of $2.9 million,  net of purchase price adjustments. The sale of the remaining oil and gas properties in the Permian Basin are expected to close during the first half of 2020 for total consideration of $0.1 million subject to customary purchase price adjustments.  We recognized impairment expense of $8.0 million during the year ended December 31, 2019 related to this sale.  As of December 31, 2019, the remaining oil and natural gas properties in the Permian Basin were classified as held for sale; $0.2 million of the assets held for sale and $0.1 million of the ARO classified as liabilities held for sale on the consolidated balance sheet were attributable to these oil and natural gas properties not yet sold.

 

In the fourth quarter of 2019, we closed on multiple sales comprising the remaining of its oil and natural gas properties in the Mid-Continent area for the total consideration of $0.7 million, net of purchase price adjustments. We recognized impairment expense of $4.9 million during the year ended December 31, 2019 related to these sales.

 

In 2019, we closed on multiple sales of certain its non-core oil and natural gas properties for total consideration of $0.7 million. We recognized a gain of $0.1 million during the year ended December 31, 2019 related to these sales.

 

In March 2020, we signed a purchase and sale agreement to sell all of its Michigan oil and natural gas properties for a purchase price of $4.8 million, subject to an adjustment based on the value of certain derivative contracts and other customary purchase price adjustments. As a result, we recognized an impairment of $8.8 million during the year ended December 31, 2019.

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, Ltd. (“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”), with an initial term through December 31, 2020, pursuant to which EnerVest

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operates the majority of our properties and provides other administrative services. See Note 14 and 18 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

 

As of December 31, 2019, our oil and natural gas properties were located in the Appalachian Basin (which includes the Utica Shale), Michigan, the Barnett Shale and the Permian Basin.

 

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, 2019 were 99.6 Bcfe, 63% of which is natural gas. During 2019, we did not drill any wells in the Appalachian Basin. As of December 31, 2019, we owned an average 60% working interest in 9,787 gross productive wells in this area.

 

Michigan

 

Our properties are located in the Antrim Shale reservoir, primarily in Otsego, Montmorency and Manistee counties in northern Michigan. Our estimated net proved reserves as of December 31, 2019 were 55.8 Bcfe, 98% of which is natural gas. During 2019,  we did not drill any wells in Michigan. As of December 31, 2019, we owned an average 70% working interest in 1,360 gross productive wells in this area. In March 2020, we signed a purchase and sale agreement to sell our Michigan properties. See —Current Developments—Divestitures” above for additional information.

 

Barnett Shale

 

Our properties are located in Denton, Parker and Wise counties in Northern Texas. Our estimated net proved reserves as of December 31, 2019 were 0.3 Bcfe, 100% of which is natural gas. During 2019, we did not drill any wells in the Barnett Shale. As of December 31, 2019, we owned an average 21% working interest in 13 gross productive wells in this area. The sale of the remaining oil and gas properties in the Barnett Shale are expected to close during the first half of 2020. See —Current Developments—Divestitures” above for additional information.

 

Permian Basin

 

Our properties are primarily located in the Lea and Eddy counties in New Mexico. Our estimated net proved reserves as of December 31, 2019 were 0.1 Bcfe, 34% of which is natural gas. During 2019,  we did not drill any wells in the Permian Basin. As of December 31, 2019, we owned an average 96% working interest in 3 gross productive wells in this area. The sale of the remaining oil and gas properties in the Permian Basin is expected to close during the first half of 2020. See —Current Developments—Divestitures” above for additional information.

 

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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 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, 2019:

 

 

 

 

 

 

 

 

 

 

 

    

 

    

 

    

Natural Gas

    

 

 

 

 

 

Natural Gas

 

Liquids

 

 

 

 

Oil (MMBbls)

 

(Bcf)

 

(MMBbls)

 

Bcfe

Proved reserves:

 

  

 

  

 

  

 

  

Developed

 

5.6

 

118.0

 

0.7

 

155.8

Undeveloped

 

 —

 

 —

 

 —

 

 —

Total

 

5.6

 

118.0

 

0.7

 

155.8

 

In addition, the following table summarizes information about our proved reserves by geographic region as of December 31, 2019:

 

 

 

 

 

 

 

 

 

 

 

 

Estimated Net Proved Reserves

 

    

 

    

 

    

Natural Gas

    

 

 

 

Oil

 

Natural Gas 

 

Liquids

 

 

 

 

(MMBbls)

 

(Bcf)

 

(MMBbls)

 

Bcfe

Appalachian Basin

 

5.6

 

63.0

 

0.5

 

99.6

Michigan (1)

 

 —

 

54.6

 

0.2

 

55.8

Barnett Shale (1)

 

 —

 

0.3

 

 —

 

0.3

Permian Basin (1)

 

 —

 

0.1

 

 —

 

0.1

Total

 

5.6

 

118.0

 

0.7

 

155.8


(1)The sales of the remaining oil and gas properties in the Barnett Shale and Permian Basin are expected to close during the first half of 2020. In March 2020, we signed a purchase and sale agreement to sell our Michigan properties. 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

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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 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, 2019, our proved reserves had a standardized measure of discounted future net cash flows of $106.9 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 $110.5 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, 2019 (dollars in millions):

 

 

 

 

 

Standardized measure

    

$

106.9

Future income taxes, discounted at 10%

 

 

3.6

PV-10

 

$

110.5

 

Our Proved Undeveloped Reserves

 

We annually review all PUDs to ensure an appropriate plan for development exists. At December 31, 2019, we had no PUDs compared with 13.4 Bcfe of PUDs at December 31, 2018. The following table describes the changes in PUDs during 2019:

 

 

 

 

 

    

Bcfe

PUDs as of December 31, 2018

 

13.4

Revisions of previous estimates

 

(1.1)

Sales of minerals in place

 

(12.3)

PUDs as of December 31, 2019

 

 —

 

The following describes the material changes to our PUDs during 2019:

 

Revisions of previous estimates.  The review of our PUDs for 2019 resulted in a revision of 1.1 Bcfe. This change from prior estimates related to our PUDs primarily results from change in commodity pricing and the availability of capital required to develop the PUDs within the SEC five-year development limitation on PUDs.

 

Sales of minerals in place.  During 2019, we sold certain of our oil and gas properties in Barnett Shale which included 12.3 Bcfe of PUDs.

 

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

 

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 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 Wright as our independent petroleum engineers. We provided information about our oil and natural gas properties, including production profiles, prices and costs, to Wright, and they prepared their own estimate 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 report of Wright, which is included as an exhibit to this annual report on Form 10–K.

 

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 Wright to ensure the integrity, accuracy and timeliness of data furnished to 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 Wright to review properties and discuss the methods and assumptions used by 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 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, 2019. 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

Appalachian Basin:

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

1,621

 

4,064

 

5,685

 

1,574

 

3,813

 

5,387

Non–operated

 

436

 

3,666

 

4,102

 

32

 

449

 

481

Michigan: (1)

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 1

 

1,184

 

1,185

 

 1

 

942

 

943

Non–operated

 

23

 

152

 

175

 

 2

 

 8

 

10

Barnett Shale: (1)

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Non–operated

 

 —

 

13

 

13

 

 —

 

 3

 

 3

Permian Basin: (1)

 

  

 

  

 

  

 

  

 

  

 

  

Operated

 

 —

 

 3

 

 3

 

 —

 

 3

 

 3

Non–operated

 

 —

 

 —

 

 —

 

 —

 

 —

 

 —

Total (2)

 

2,081

 

9,082

 

11,163

 

1,609

 

5,218

 

6,827


(1)The sales of the remaining oil and gas properties in the Barnett Shale and Permian Basin are expected to close during the first half of 2020. In March 2020, we signed a purchase and sale agreement to sell our Michigan properties. See —Current Developments—Divestitures” above for additional information.

 

(2)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, 2019:

 

 

 

 

 

 

 

 

 

 

 

 

Developed Acreage

 

Undeveloped Acreage

 

    

Gross

    

Net

    

Gross

    

Net

Appalachian Basin

 

596,554

 

455,128

 

320,269

 

258,273

Michigan (1)

 

86,500

 

65,361

 

1,038

 

1,035

Barnett Shale (1)

 

755

 

292

 

12

 

 4

Permian Basin (1)

 

40

 

18

 

 —

 

 —

Total

 

683,849

 

520,799

 

321,319

 

259,312


(1)The sales of the remaining oil and gas properties in the Barnett Shale and Permian Basin are expected to close during the first half of 2020. In March 2020, we signed a purchase and sale agreement to sell our Michigan properties. See —Current Developments—Divestitures” above for additional information.

 

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

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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.

 

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 year ended December 31, 2019 and seven months ended December 31, 2018, and for the Predecessor five months ended May 31, 2018 and year ended December 31, 2017 from the Appalachian Basin and Michigan, which are the only fields during those years for which our estimated net proved reserves at December 31, 2019 attributable to the field represented 15% or more of our total estimated net proved reserves at December 31, 2019:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Successor

 

 

Predecessor

 

 

 

Seven Months

 

 

Five Months

 

 

 

Year Ended

 

Ended

 

 

Ended

 

Year Ended

 

December 31,

 

December 31,

 

 

May 31,

 

December 31,

 

2019

 

2018

 

    

2018

    

2017

Oil

 

  

 

 

  

 

 

 

  

 

 

  

Production (MBbls):

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

 

440

 

 

290

 

 

 

209

 

 

541

Michigan

 

 4

 

 

 —

 

 

 

 —

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Bbl:

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

$

54.31

 

$

62.22

 

 

$

61.63

 

$

47.29

Michigan

$

51.58

 

$

 —

 

 

$

 —

 

$

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas

 

  

 

 

  

 

 

 

  

 

 

  

Production (MMcf):

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

 

7,844

 

 

5,159

 

 

 

3,458

 

 

11,465

Michigan

 

4,280

 

 

 —

 

 

 

 —

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Mcf:

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

$

2.44

 

$

2.78

 

 

$

2.44

 

$

2.45

Michigan

$

2.44

 

$

 —

 

 

$

 —

 

$

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Natural Gas Liquids

 

  

 

 

  

 

 

 

  

 

 

  

Production (MBbls):

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

 

33

 

 

26

 

 

 

29

 

 

43

Michigan

 

10

 

 

 —

 

 

 

 —

 

 

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Average sales price per Bbl:

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

$

16.95

 

$

20.00

 

 

$

28.79

 

$

15.53

Michigan

$

18.56

 

$

 —

 

 

$

 —

 

$

 —

 

 

 

 

 

 

 

 

 

 

 

 

 

Average unit costs per Mcfe:

 

  

 

 

  

 

 

 

  

 

 

  

Lease operating expenses per Mcfe (1)

 

  

 

 

  

 

 

 

  

 

 

  

Appalachian Basin

$

2.46

 

$

2.23

 

 

$

2.31

 

$

1.85

Michigan

$

2.00

 

$

 —

 

 

$

 —

 

$

 —


(1)Excluding ad valorem taxes.

 

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Our Drilling Activity

 

We do not currently have any planned drilling activity, but would expect to concentrate any future drilling activity on low risk development drilling opportunities. The number and types of wells we may drill in the future would 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.

 

For the year ended December 31, 2019, we did not participate in the drilling of any development wells.

 

The following table summarizes our approximate gross and net interest in development wells completed during the year ended December 31, 2018 and 2017, 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.

 

 

 

 

 

 

 

 

 

 

2018

    

2017

Gross wells:

  

 

  

Productive

30.0

 

33.0

Dry

 —

 

 —

Total

30.0

 

33.0

Net wells:

  

 

  

Productive

6.3

 

3.8

Dry

 —

 

 —

Total

6.3

 

3.8

 

We did not drill any exploratory wells during the year ended December 31, 2019 or 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 year ended December 31, 2017.

 

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 2019,  Bedrock Production, LLC., Ergon Oil Purchasing, INC. and American Refining Group, INC. accounted for 17.4%, 11.4% and 10.1%, respectively, of consolidated oil, natural gas and natural gas liquids revenues. 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. 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 contracting for drilling rigs and related equipment and securing trained personnel. Many of these competitors have financial and technical resources and staffs substantially larger than ours. 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 any future development and exploitation by us.

 

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 and Michigan. As a result, we generally perform the majority of our drilling in these areas during the summer and autumn months. 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.

 

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;

 

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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 and the energy extraction enforcement initiative was discontinued as of the end of fiscal year 2019. 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 was required to propose, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations is not necessary. In April 2019, the EPA determined in a document entitled “Management of Oil and Gas Exploration, Development and Production Wastes: Factors Informing a Decision on the Need for Regulatory Action” that revisions to these oil and gas waste regulations were not necessary because the main causes for uncontrolled releases of oil and gas waste are appropriately and more readily addressed within the framework of existing state regulatory programs. 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.

 

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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” (the “Clean Water Rule”) which 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 Clean Water Rule in July 2017 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. In October 2019, the EPA issued a final rule repealing the Clean Water Rule (which became effective in December 2019 and has already been challenged in federal district courts in New Mexico, New York, and South Carolina). Litigation regarding the Clean Water Rule in the federal district courts resulted in patchwork application of the rule in some states (e.g. Pennsylvania), but not others (e.g. Texas, Louisiana) and the October 2019 final repeal rule sought to undo this division and revive the 1986 regulations that were in place before the Clean Water Rule was issued. The final rule revising the definition of “waters of the United States” is expected in 2020 and several groups have already announced their intention to challenge that 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

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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 (oral arguments were heard in the case in January 2020).

 

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 (as of October 2019, the EPA had requested a stay of the litigation pending its proposed overhaul of the 2016 methane requirements). In September 2019, the EPA proposed to remove transmission sources from the purview of the 2012 and 2016 rules, thereby rescinding the NSPS standards currently applicable to such sources, including limitations on methane emissions. The proposed rule would also rescind methane emissions limits for production and processing sources, but would maintain emissions limits for volatile organic compounds, reasoning that a reduction in such emissions also reduces methane, so separate methane limitations would be redundant. In the alternative, EPA also proposed to rescind the methane requirements in the NSPS for all oil and natural gas sources, without removing any sources from the source category. The status of future regulation remains unclear but revisions to the NSPS standards 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

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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.

 

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. In January 2020, the White House Council on Environmental Quality (“CEQ”) proposed changes to NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule proposes to narrow the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.”  Changes to the NEPA regulations could have an effect on our operations and our ability to obtain governmental permits. We continuously evaluate the effect of new rules on our business.

 

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. In addition, there are Congressional proposals that could result in significant curtailment of oil and natural gas development and production, and hydraulic fracturing in particular, on BLM lands. 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

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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 (as of October 2019, the EPA had requested a stay of the litigation pending its proposed overhaul of the 2016 methane requirements). In September 2019, the EPA proposed to remove transmission sources from the purview of the NSPS standards, thereby rescinding the limitations on methane and volatile organic compounds emissions currently applicable to those sources. The proposed rule would also rescind methane emissions limits for production and processing sources, but would maintain emissions limits for volatile organic compounds, reasoning that a reduction in such emissions also reduces methane, so separate methane limitations would be redundant. In the alternative, EPA also proposed to rescind the methane requirements in the NSPS for all oil and natural gas sources, without removing any sources from the source category. 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.

 

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.

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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, 2019, 2018 and 2017. Additionally, we are not aware of any environmental issues or claims that will require material capital expenditures during 2020 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.

 

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

 

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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.

 

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, as amended (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 and policies, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper may release its pipeline capacity to another potential shipper, which provisions include FERC’s “shipper-must-have-title” rule and the prohibition against buy-sell transactions. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release, shipper-must-have-title, or buy sell rules, could subject a shipper to substantial civil penalties and other remedies from FERC.

 

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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 provide information concerning the greenhouse gas (“GHG”) emissions resulting from the activities 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, and which required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emissions from specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers to be served by proposed interstate natural gas pipeline projects.  However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts.

 

Under the Energy Policy Act of 2005, FERC adopted an anti-market manipulation rule and was given greater civil penalty authority under the Natural Gas Act (“NGA”) to impose penalties of approximately $1.0 million per day for each violation of any of its regulations or orders. The prices at which we sell oil, natural gas, or natural gas liquids are not currently subject to federal rate regulation and, for the most part, not subject to state regulation. FERC also has authority to require the disgorgement of profits associated with any violation of its regulations and orders. However, certain sales-for-resale are exempt from FERC jurisdiction and as such, our activities with regards to such sales may not be subject to FERC’s market manipulation jurisdiction.  However, with regard to our physical sales of these energy commodities, we are required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the Commodity Futures Trading Commission (“CFTC”).  Violations of such laws and rules could result in substantial civil penalties and other remedies imposed by the CFTC. Also, under the Energy Independence and Security Act of 2007 and regulations promulgated thereunder, the Federal Trade Commission (“FTC”) has adopted anti-market manipulation rules relating to wholesale crude oil sales. Violations of such laws and rules could result in civil penalties imposed by the FTC.

 

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 that oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to its 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, but FERC has not acted on rehearing. It is uncertain what impact this FERC order may have on other oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

 

Gathering services, which occur on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, are regulated by the states onshore and in state waters. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a FERC jurisdictional transportation function, the FERC’s determination as to the classification of facilities is done on a case-by-case basis. 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 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”), the Hazardous Liquids Pipeline Safety Act of 1979, as amended (“HLPSA”), the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011 (“2011 Pipeline Safety Act”), and the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2016 (“2016 PIPES Act”). 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

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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 and 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 sales or prices 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 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.

 

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Derivatives

 

Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) amended the Commodity Exchange Act and establishes federal oversight and regulation of over-the-counter (“OTC”) derivatives and requires 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 16, 2016, and re-issued on February 27, 2020, 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 16, 2016, and re-issued on December 19, 2019, 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 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, and on February 20, 2020, the CFTC issued a Notice of Proposed Rulemaking to amend certain swap data recordkeeping and reporting requirements which propose to streamline the requirements for reporting new swaps, define and adopt swap elements that harmonize with international technical guidance, and reduce reporting burdens for reporting counterparties that are not swap dealers or major swap participants.

 

With regard to our derivatives transactions, we are required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the CFTC. Violations of such laws and rules could result in substantial civil penalties and other remedies imposed by the CFTC.

 

Other Regulations

 

In addition to the regulation of oil, natural gas, and natural gas liquids 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

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insurance policies are subject to certain customary exclusions and limitations. In addition, we maintain $75.0 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, 2019, 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.

 

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” 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.

 

 

 

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Risks Related to our Business

 

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

 

Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and natural gas liquids, and the prices we receive for our production are volatile.  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;

 

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 OPEC 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;

 

the price and availability of alternative fuels; and

 

global or national health epidemics or concerns, such as the recent COVID-19 outbreak, which may reduce demand for oil, natural gas and related products because of reduced global or national economic activity.

 

 

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

 

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

 

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

 

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.

 

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

Upon our emergence from bankruptcy in 2018, we adopted fresh start accounting. Accordingly, our financial conditions and results of operations subsequent to emergence from bankruptcy are not comparable to the financial condition or results of operations reflected in the Predecessor’s historical financial statements prior to our emergence from bankruptcy. Investors may find it more difficult to analyze the performance of the Company due to the limited comparable historical financial information.

Outbreaks of communicable diseases could adversely affect our business, financial condition and results of operations.

 

Global or national health concerns, including the outbreak of pandemic or contagious disease, can negatively impact the global economy and, therefore, demand and pricing for oil and natural gas products. For example, there have been recent outbreaks across the world, including the United States, of a highly transmissible and pathogenic virus that is generally referred to as COVID-19. The outbreak of communicable diseases, or the perception that such an outbreak could occur, could result in a widespread public health crisis that could adversely affect the economies and financial markets of many countries, resulting in an economic downturn that would negatively impact the demand for oil and natural gas products. Furthermore, uncertainty regarding the impact of any outbreak of pandemic or contagious disease, including COVID-19, could lead to increased volatility in oil and natural gas prices. In addition, if a pandemic or epidemic, including COVID-19, were to impact a location where we have a high concentration of our business and resources, the workforce we depend on could be affected by such occurrence, which could also significantly disrupt our results of operations. The duration of such a disruption and the related financial impact from COVID-19 and other such pandemics cannot be reasonably estimated at this time. The occurrence or continuation of any of these events could lead us to incur additional impairment charges in the future, which could have a material adverse effect on our financial condition, our results of operations and our ability to implement our strategy.

 

The ability or willingness of the Organization of Petroleum Exporting Countries and other oil exporting nations to set and maintain production levels has a significant impact on commodity prices.

 

The OPEC is an intergovernmental organization that seeks to manage the price and supply of oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations, have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. In March 2020, members of OPEC and Russia considered extending and potentially increasing these oil production cuts. However, these negotiations were unsuccessful. As a result, Saudi Arabia announced an immediate reduction in export prices and Russia announced that all previously agreed oil production cuts will expire on April 1, 2020. These actions led to an immediate and steep decrease in oil prices. There can be no assurance that OPEC members and other oil exporting nations will agree to future production cuts or other

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actions to support and stabilize oil prices, nor can there be any assurance that they will not further reduce oil prices or increase production. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could cause us to incur future impairment charges that adversely affect our business, financial condition and results of operations.

 

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

 

Under the Services Agreement, EnerVest provides services to us such as accounting, human resources, office space, digital infrastructure and other administrative services. If EnerVest was 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, 2019, EnerVest operated oil and natural gas properties representing 88% of our proved oil and gas reserves and also had an economic interest in some of our properties. 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.

 

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.

 

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 a financial institution who is a lender under our New 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. We have commodity contracts covering approximately 95% of our estimated production attributable to our net proved reserves for 2020. Currently, we have no commodity price

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hedges for any periods subsequent to 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.

 

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.

 

Changes to CFTC 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, capital requirements, or swap reporting 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 law 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 law 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 FERC, CFTC or FTC, we could be subject to substantial penalties and other remedies.

 

Under the Energy Policy Act of 2005, FERC has been given greater civil penalty authority under the NGA, including the ability to impose penalties of approximately $1.0 million per day for each violation of its rules or orders. FERC also has authority to require the 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 counterparties’ otherwise non-FERC jurisdictional operations to FERC annual reporting and posting requirements. We also may be required to 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, the CFTC has adopted anti-market manipulation, fraud and disruptive trading practices rules relating to commodities, futures contracts, options on futures, and swaps. Failure to comply with those rules could lead to imposition of penalties or other remedies by the CFTC. Similarly, under the Energy Independence and Security Act of 2007 and regulations promulgated thereunder, the FTC has adopted anti-market manipulation rules relating to wholesale crude oil sales. Failure to comply with those rules could lead to imposition of penalties by the FTC.

 

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Additional rules and legislation pertaining to those and other matters may be considered or adopted by Congress, the FERC, the CFTC, or the FTC 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 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 2019, we completed divestitures of several of our assets and we have additional divestitures pending, as discussed in “Item 1. Business—Overview—Divestitures,” 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.

 

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 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. However, due to recent and current commodity prices, we do not currently have plans for development drilling in 2020.  

 

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 a report from Wright, an independent petroleum engineering firm 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

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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.

 

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 business depends on gathering and compression facilities owned by third parties and transportation facilities owned by third party transporters and we rely on third parties to gather and deliver our oil, natural gas and natural gas liquids to certain designated interconnects with third-party transporters. Any limitation in the availability of those facilities or delay in providing interconnections to newly drilled wells would interfere with our ability to market the oil, natural gas and natural gas liquids we produce and could reduce our revenues.

 

The marketability of our oil, natural gas and natural gas liquids production depends in part on the availability, proximity and capacity of pipeline systems owned by third parties in the respective operating areas. The amount of oil and natural gas that can be produced and sold is subject to curtailment in certain circumstances, such as pipeline interruptions due to scheduled and unscheduled maintenance, excessive pressure, physical damage to the gathering, compression or transportation system, or lack of contracted capacity on such systems. The curtailments arising from these and similar circumstances may last from a few days to several months. In many cases, we are provided only with limited, if any, notice as to when these circumstances will arise and their duration. In addition, some of our wells are drilled in locations that are not serviced by gathering and transportation pipelines, or the gathering and transportation pipelines in the area may not have sufficient capacity to transport the additional production. As a result, we may not be able to sell the oil and natural gas production from these wells until the necessary gathering and transportation systems are constructed. Any significant curtailment in gathering system or pipeline capacity, or significant delay in the construction of necessary gathering, compression and transportation facilities, could reduce our revenues.

 

The third parties on whom we rely for gathering, compression and transportation services are subject to complex federal, state and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business.

 

The operations of the third parties on whom we rely for gathering, compression and transportation services are subject to complex and stringent laws and regulations that require obtaining and maintaining numerous permits, approvals and certifications from various federal, state and local government authorities. These third parties may incur substantial costs in order to comply with existing laws and regulations. If existing laws and regulations governing such third-party services are revised or reinterpreted, or if new laws and regulations become applicable to their operations, these changes may affect the costs that we pay for such services. Similarly, a failure to comply with such laws and regulations by the third parties on whom we rely could have a material adverse effect on our business, financial condition and results of operations.

 

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Our financial condition and results of operations may be materially adversely affected if we incur costs and liabilities due to a failure to comply with environmental regulations or a release of hazardous substances into the environment.

 

We may incur significant costs and liabilities as a result of environmental requirements applicable to the operation of our wells, gathering systems and other facilities. These costs and liabilities could arise under a wide range of federal, state and local environmental laws and regulations, including, for example:

 

the Clean Air Act and comparable state laws and regulations that impose obligations related to emissions of air pollutants;

 

the Clean Water Act and comparable state laws and regulations that impose obligations related to discharges of pollutants into regulated bodies of water;

 

the Resource Conservation and Recovery Act (the “RCRA”), and comparable state laws that impose requirements for the handling and disposal of waste from our facilities;

 

the Comprehensive Environmental Response, Compensation and Liability Act (the “CERCLA”) and comparable state laws that regulate the cleanup of hazardous substances that may have been released at properties currently or previously owned or operated by us or at locations to which we have sent waste for disposal;

 

the Safe Drinking Water Act (the “SDWA”) and state or local laws and regulations related to hydraulic fracturing;

 

the Oil Pollution Act (the “OPA”) which subjects responsible parties to liability for removal costs and damages arising from an oil spill in federal jurisdictional waters;

 

the US Environmental Protection Agency (the “EPA”) community right to know regulations under the Title III of CERCLA and similar state statutes that require that we organize and/or disclose information about hazardous materials used or produced in our operations; and

 

the Endangered Species Act, which may restrict or prohibit operations in protected areas.

 

Failure to comply with these laws and regulations may trigger a variety of administrative, civil and criminal enforcement measures, including the assessment of monetary penalties, the imposition of remedial requirements, and the issuance of orders enjoining future operations. Certain environmental statutes, including RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict joint and several liability for costs required to clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released. More stringent laws and regulations, including any related to climate change and greenhouse gases, may be adopted in the future. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances or other waste products into the environment.

 

We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of conducting our operations.

 

Our operations are subject to complex and stringent laws and regulations, which are continuously being reviewed for amendment and/or expansion. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state and local governmental authorities. Failure or delay in obtaining and maintaining regulatory approvals or drilling permits could have a material adverse effect on our ability to develop our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. In addition, regulations regarding resource conservation practices and the protection of correlative rights affect our operations by limiting the quantity of oil, natural gas and natural gas liquids we may produce and sell.

 

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We are subject to, and may incur liabilities under, federal, state and local laws and regulations as interpreted and enforced by governmental authorities possessing jurisdiction over various aspects of the exploration and production of oil, natural gas and natural gas liquids.

 

For example, several states have enacted Surface Damage Acts (“SDAs”) that are designed to compensate surface owners/users for damages caused by mineral owners. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs. In addition, many states, including Texas, impose a production, ad valorem or severance tax with respect to the production and sale of oil and gas within their jurisdiction.

 

Other activities subject to regulation are:

 

the location and spacing of wells;

 

the method of drilling and completing and operating wells;

 

the rate and method of production;

 

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

 

notice to surface owners and other third parties;

 

the venting or flaring of natural gas;

 

the plugging and abandoning of wells;

 

the discharge of contaminants into water and the emission of contaminants into air;

 

the disposal of fluids used or other wastes obtained in connection with operations;

 

the marketing, transportation and reporting of production; and

 

the valuation and payment of royalties.

 

While the cost of compliance with these laws has not been material to our operations in the past, the possibility exists that new laws, regulations or enforcement policies could be more stringent and significantly increase our compliance costs. If we are not able to recover the resulting costs through insurance or increased revenues, our ability to service our debt obligations could be adversely affected.

 

Climate change legislation or regulations restricting emissions of greenhouse gases (“GHGs”) could result in increased operating costs and reduced demand for the oil, natural gas and natural gas liquids we produce.

 

The EPA requires the reporting of GHG emissions from specified large GHG emission sources, including onshore and offshore oil and natural gas production facilities and onshore oil and natural gas processing, transmission, storage and distribution facilities, which may include facilities we operate. We began reporting emissions in 2012 for emissions occurring in 2011 and continue to report as required on an annual basis.

 

More stringent laws and regulations relating to climate change and GHGs may be adopted and could cause us to incur material expenses to comply.

 

Both houses of Congress previously considered legislation to reduce emissions of GHGs and many states have adopted or considered measures to reduce GHG emission reduction levels, often involving the planned development of GHG

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emission inventories and/or cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions or major producers of fuels to acquire and surrender emission allowances. The adoption and implementation of any legislation or regulatory programs imposing reporting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations or could adversely affect demand for the oil, natural gas and natural gas liquids that we produce. Additionally, growing attention to climate change risks has resulted in increased likelihood of governmental investigations and private litigation, which could increase our costs or otherwise adversely affect our business.

 

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 EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants. 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 New Source Performance Standards (“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 the EPA to establish guidelines for limiting methane emissions from existing sources in the oil and natural gas sector; that lawsuit is currently pending (as of October 2019, the EPA had requested a stay of the litigation pending its proposed overhaul of the 2016 methane requirements). In August 2019, the EPA proposed a significant rollback to the 2016 rule that, if finalized, would rescind the volatile organic compound and methane requirements applicable to transmission sources and the methane requirements for production and processing sources, or in the alternative, rescind methane requirements applicable to all oil and natural gas sources. In late 2016, the Bureau of Land Management (the “BLM”) adopted a rule governing flaring and venting of methane from existing wells and other facilities on public and tribal lands, which could require additional equipment and emissions controls as well as inspection requirements. This rule has been challenged in court by 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.

Significant physical effects of climatic change have the potential to damage our facilities, disrupt our production activities and cause us to incur significant costs in preparing for or responding to those effects.

Climate change could have an effect on the severity of weather (including hurricanes and floods), sea levels, the arability of farmland, and water availability and quality. If such effects were to occur, our exploration and production operations have the potential to be adversely affected. Potential adverse effects could include damages to our facilities from powerful winds or rising waters in low lying areas, disruption of our production activities either because of climate-related damages to our facilities or our costs of operation potentially arising from such climatic effects, less efficient or non–routine operating practices necessitated by climate effects or increased costs for insurance coverages in the aftermath of such effects. Significant physical effects of climate change could also have an indirect effect on our financing and operations by disrupting the transportation or process related services provided by midstream companies, service companies or suppliers with whom we have a business relationship. We may not be able to recover through insurance some or any of the damages, losses or costs that may result from potential physical effects of climate change.

 

We are now subject to regulation under NSPS and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) programs, which could result in increased operating costs.

 

On April 17, 2012, the EPA issued final rules that subject oil and natural gas production, processing, transmission and storage operations to regulation under the NSPS and the NESHAP programs. The EPA rules include NSPS standards for completions of hydraulically fractured natural gas wells. Beginning January 1, 2015, operators must 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 newly 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.

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We may encounter obstacles to marketing our oil, natural gas and natural gas liquids, which could adversely impact our revenues.

 

The marketability of our production will depend in part upon the availability and capacity of natural gas gathering systems, pipelines and other transportation facilities owned by third parties. Transportation space on the gathering systems and pipelines we utilize is occasionally limited or unavailable due to repairs or improvements to facilities or due to space being utilized by other companies that have priority transportation agreements. Our access to transportation options can also be affected by US federal and state regulation of oil and natural gas production and transportation, general economic conditions and changes in supply and demand. The availability of markets is beyond our control. If market factors dramatically change, the impact on our revenues could be substantial and could adversely affect our ability to produce and market oil, natural gas and natural gas liquids, the value of our securities and our ability to service our debt obligations.

 

We may experience a temporary decline in revenues and production if we lose one of our significant customers.

 

To the extent any significant customer reduces the volume of its oil or natural gas purchases from us, we could experience a temporary interruption in sales of, or a lower price for, our production and our revenues which could adversely affect our ability to service our debt obligations.

 

Oil and gas exploration and production activities are complex and involve risks that could lead to legal proceedings resulting in the incurrence of substantial liabilities.

 

Like many oil and gas companies, we are from time to time involved in various legal and other proceedings in the ordinary course of business, such as title, royalty or contractual disputes, regulatory compliance matters and personal injury or property damage matters. Such legal proceedings are inherently uncertain and their results cannot be predicted. Regardless of the outcome, such proceedings could have an adverse impact on us because of legal costs, diversion of management and other personnel and other factors. In addition, it is possible that a resolution of one or more such proceedings could result in liability, penalties or sanctions, as well as judgments, consent decrees or orders requiring a change in our business practices, which could materially and adversely affect our business, operating results and financial condition. Accruals for such liabilities, penalties or sanctions may be insufficient, and judgments and estimates to determine accruals or range of losses related to legal and other proceedings could change from one period to the next, and such changes could be material.

 

Loss of our information and computer systems could adversely affect our business.

 

We are heavily dependent on our information systems and computer based programs, including our well operations information, seismic data, electronic data processing and accounting data. If any of such programs or systems were to fail or create erroneous information in our hardware or software network infrastructure, possible consequences include our loss of communication links, inability to find, produce, process and sell oil and natural gas and inability to automatically process commercial transactions or engage in similar automated or computerized business activities. Any such consequence could have a material adverse effect on our business.

 

A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.

 

The oil and gas industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. For example, software programs are used to interpret seismic data, manage drilling rigs, production equipment and gathering and transportation systems, conduct reservoir modeling and reserves estimation, and for compliance reporting. The use of mobile communication devices has increased rapidly. Industrial control systems such as SCADA (supervisory control and data acquisition) now control large scale processes that can include multiple sites and long distances, such as power generation and transmission, communications and oil and gas pipelines.

 

We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, all of which is managed by EnerVest pursuant to the Services Agreement, to process and record

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financial and operating data, communicate with our employees, vendors and service providers, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our vendors, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities and global competition for oil and gas resources make certain information the target of theft or misappropriation.

 

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, also have increased. A cyber-attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. SCADA-based systems are potentially vulnerable to targeted cyber-attacks due to their critical role in operations.

 

Our technologies, systems, networks, and those of our vendors and service providers may become the target of cyber-attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

 

A cyber incident involving our information systems and related infrastructure, or that of our vendors and service providers, could disrupt our business plans and negatively impact our operations in the following ways, among others:

 

unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

 

data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;

 

data corruption or operational disruption of production infrastructure could result in loss of production, or accidental discharge;

 

a  cyber-attack on a vendor or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;

 

a cyber-attack on a third party gathering or pipeline service provider could prevent us from marketing our production, resulting in a loss of revenues;

 

a cyber-attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;

 

a cyber-attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;

 

a deliberate corruption of our financial or operational data could result in events of non-compliance which could lead to regulatory fines or penalties; and

 

business interruptions could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.

 

Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities.

 

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Risks Related to our Common Stock

 

We have no current plans to pay dividends on our common stock and, consequently, our stockholders’ only opportunities to achieve a return on their investment may be our stock price’s potential appreciation or our potential dissolution and liquidation or sale for cash.

We have no current plans to pay dividends on our common stock. Consequently, unless our board of directors authorizes the payment of dividends in the future, one of our stockholders’ only opportunities to achieve a return on their investment in us will be if the market price of our common stock appreciates, which may not occur, and the stockholders sell their shares at a profit. There is no guarantee that the price of our common stock will ever exceed the price that the stockholders paid. Additionally, our stockholders could achieve a return on their investment in the event our board of directors pursues a dissolution and liquidation or sale for cash. In the event of a dissolution and liquidation or sale, whether voluntary or involuntary, the amount of cash available for distribution to our stockholders will depend heavily on the timing of such decision. In addition, if our board of directors were to approve and recommend and pursue a dissolution and liquidation, we would be required under Delaware corporate law to pay our outstanding obligations, as well as to make reasonable provision for contingent and unknown obligations, prior to making any distributions in liquidation to our stockholders. As a result of this requirement, a portion of our assets may need to be reserved pending the resolution of such obligations and the proceeds and/or our assets may not be sufficient to repay the aggregate investment you purchased in our company. In this event, you could lose some or all of your investment.

There may be circumstances in which the interests of our significant stockholders could be in conflict with the interests of our other stockholders.

Certain of our stockholders own a significant portion of our outstanding common stock. As of December 31, 2019, funds associated with Finepoint Capital LP and FS Investments collectively owned approximately 46% of our outstanding stock and CQS (UK) LLP owned approximately 24% of our outstanding stock. Circumstances may arise in which these stockholders may have an interest in pursuing or preventing acquisitions, divestitures or other transactions, including the issuance of additional shares or debt, that, in their judgment, could enhance their investment in the Company. Such transactions might adversely affect us or other holders of our common stock.

Our significant concentration of share ownership may adversely affect the trading price of our common stock.

As of December 31, 2019, funds associated with Finepoint Capital LP and FS Investments collectively owned approximately 46% of our outstanding stock and CQS (UK) LLP owned approximately 24% of our outstanding stock, and Finepoint Capital LP and FS Investments each have a representative on our board of directors. Our significant concentration of share ownership may adversely affect the trading price of our common stock because of the lack of trading volume in our stock and because investors may perceive disadvantages in owning shares in companies with significant stockholders.

We have experienced recent volatility in the market price and trading volume of our common stock and may continue to do so in the future.

The trading price of shares of our common stock has fluctuated widely and in the future may be subject to similar fluctuations. The trading price of our common stock may be affected by a number of factors, including the volatility of oil, natural gas, and natural gas liquids prices, our operating results, changes in our earnings estimates, additions or departures of key personnel, our financial condition and liquidity, drilling activities, legislative and regulatory changes, general conditions in the oil and natural gas exploration and development industry, general economic conditions, and general conditions in the securities markets. In particular, a significant or extended decline in oil, natural gas and natural gas liquids prices could have a material adverse effect our sales price of our common stock. Other risks described in this annual report could also materially and adversely affect our share price.

Although our common stock is listed on the OTCQX U.S. Premier Marketplace, we cannot assure you that an active public market will continue for our common stock or that will be able to continue to meet the listing requirements of the OTCQX U.S. Premier Marketplace. If an active public market for our common stock does not continue, the trading price

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and liquidity of our common stock will be materially and adversely affected. If there is a thin trading market or “float” for our stock, the market price for our common stock may fluctuate significantly more than the stock market as a whole. Without a large float, our common stock would be less liquid than the stock of companies with broader public ownership and, as a result, the trading prices of our common stock may be more volatile. In addition, in the absence of an active public trading market, investors may be unable to liquidate their investment in us.

We may choose to deregister our common stock under the Exchange Act, which could negatively affect the liquidity and trading prices of our common stock and would result in less disclosure about the Company.

Given the cost and resource demands of being a public company, we may decide to “go dark,” or discontinue our obligation to make periodic filings with the SEC, by deregistering our securities. After going dark, there would be a substantial decrease in disclosure by us of our operations and prospects, and a substantial decrease in the liquidity in our common stock even though stockholders may still continue to trade our common stock on the OTC Pink Sheets. As a result of going dark, investors may find it more difficult to dispose of or obtain accurate quotations as to the market value of our common stock, and the ability of our stockholders to sell our common stock in the secondary market may be materially limited.

Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could discourage acquisition bids or merger proposals, even if such acquisition or merger may be in our stockholders’ best interests.

Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation and bylaws could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:

 

advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders; and

 

limitations on the ability of our stockholders to call special meetings or act by written consent.

 

Delaware law prohibits us from engaging in any business combination with any “interested stockholder,” meaning generally that a stockholder who beneficially owns more than 15% of our stock cannot acquire us for a period of three years from the date this person became an interested stockholder, unless various conditions are met, such as approval of the transaction by our board of directors.

 

We are a smaller reporting company, and we cannot be certain if the reduced disclosure requirements applicable to smaller reporting companies will make our common stock less attractive to investors.

We are currently a “smaller reporting company”, meaning that we are not an investment company, an asset- backed issuer, or a majority-owned subsidiary of a parent company that is not a smaller reporting company and have a non-affiliated public float of less than $250 million or annual revenues of less than $100.0 million and public float of less than $700 million during the most recently completed fiscal year. In the event that we are still considered a “smaller reporting company,” at such time as we cease being an “emerging growth company,” we will be required to provide additional disclosure in our SEC filings. However, similar to an “emerging growth companies”, “smaller reporting companies” are able to provide simplified executive compensation disclosures in their filings; are exempt from the provisions of Section 404(b) of the Sarbanes-Oxley Act requiring that independent registered public accounting firms provide an attestation report on the effectiveness of internal control over financial reporting; and have certain other decreased disclosure obligations in their SEC filings, including, among other things, only being required to provide two years of audited financial statements in annual reports and in a registration statement under the Exchange Act on Form 10. Decreased disclosures in our SEC filings due to our status as a “smaller reporting company” may make it harder for investors to analyze our results of operations and financial prospects.

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ITEM 1B. UNRESOLVED STAFF COMMENTS

 

None.

 

ITEM 2. PROPERTIES

 

Information regarding our properties is contained in “Item 1. Business — Overview,” “Item 1. Business —  Oil and Natural Gas Producing Activities” and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Results of Operations” contained herein.

 

ITEM 3. LEGAL PROCEEDINGS

 

We are involved in disputes or legal actions arising in the ordinary course of business. We do not believe the outcome of such disputes or legal actions will have a material effect on our consolidated financial statements. No amounts, other than as described below, were accrued as of December 31, 2019 or 2018.

 

In August 2018, we were notified by the Office of Natural Resources Revenue (“ONRR”) of potential underpayments of royalties related to certain leases for the period of 2009 through 2018. We have submitted amended royalty filings for the period of 2009 to 2018, pursuant to which Harvest has an additional liability of approximately $5.0 million. This amount will be paid upon ONRR review and concurrence with the accuracy of royalties per the amended filings.  We recognized an accrual for the estimated liability for the period of 2009 to 2018 as of both December 31, 2019 and 2018.

 

Also, in August 2019, we agreed to a litigation settlement of $0.6 million related to such matters in the ordinary course of business, the expense for which is included in “General and administrative expenses” in the consolidated statements of operations for the year ended December 31, 2019.

 

ITEM 4. MINE SAFETY DISCLOSURES

 

Not applicable.

PART II

 

ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES

 

Market Information

 

Our common stock is traded on the OTCQX U.S. Premier Marketplace (the “OTCQX”) under the symbol “HRST.” As of April 8, 2020, we had 10,173,707 shares of common stock issued and outstanding, held by approximately 279 registered holders.

 

Issuer Purchases of Equity Securities

 

On December 3, 2019, the board of directors of Harvest approved a share repurchase program that gives the Company the ability to repurchase up to $5.0 million of shares of the Company’s outstanding common stock (the “Repurchase Program”). See Note 15 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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The Company repurchased the following shares under the Repurchase Program and from employees for the payment of withholding taxes due on vesting awards of restricted stock units previously issued under our share-based compensation plan:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Total Number of Shares

 

Approximate Dollar Value

 

 

Total Number of Shares

 

Average Price

 

Purchased as Part of

 

of Shares that may yet

Period

    

Purchased

    

Per Share

    

Publicly Announced Program

    

be Purchased Under Program

June 2019

 

11,692

 

$

14.40

 

n/a

 

n/a

September 2019

 

10,469

 

$

12.21

 

n/a

 

n/a

December 2019

 

3,032

 

$

6.34

 

2,379

 

4,984,796

 

 

 

ITEM 6. SELECTED FINANCIAL DATA 

 

 Not presented in accordance with smaller reporting company guidelines.  

 

ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS

 

Management’s Discussion and Analysis of Financial Condition and Results of Operations should be read in conjunction with “Item 8. Financial Statements and Supplementary Data” contained herein.

 

OVERVIEW

 

Harvest Oil & Gas Corp. (“Harvest” or “Successor”) 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” 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, 2019, our oil and natural gas properties are located in the Appalachian Basin (which includes the Utica Shale), Michigan, the Barnett Shale, and the Permian Basin. As of December 31, 2019, we had estimated net proved reserves of 155.8 Bcfe and a standardized measure of $106.9 million. Of our total net proved reserves, 100% are proved developed, 76% are natural gas and 88% are operated.

 

We continue to review strategic alternatives in order to maximize shareholder value. We divested significant assets during 2019 and are also actively considering the potential divestiture of all of our remaining assets as well as a potential sale or merger of the Company. In addition, we are reviewing options to reduce our overall cost structure to more closely align with our asset base. There can be no assurance that we will be successful in the near-term in divesting our remaining assets or merging the Company and the outcome of our cost-cutting efforts is still being developed.

 

Divestitures

 

During 2019 and 2020, we announced or closed a number of divestitures. See Note 8 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Emergence from Voluntary Reorganization under Chapter 11

 

On March 13, 2018, the Debtors entered into the Restructuring Support Agreement with certain stakeholders which 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”). 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

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provisions of the Bankruptcy Code and orders of the Bankruptcy Court as “Debtors-in-Possession.” On May 17, 2018, the Bankruptcy Court entered the Confirmation Order confirming the Plan.

 

On June 4, 2018 (the “Effective Date”), 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 and the successor reporting company to EVEP pursuant to Rule 15d-5 of the Securities Exchange Act of 1934, as amended.

 

Although we are not a debtor-in-possession, the Predecessor was a debtor-in-possession between April 2, 2018 and June 4, 2018. As such, certain aspects of the Chapter 11 proceedings and related matters are described below in order to provide context to the Company’s financial condition and results of operations for the period presented. See Note 2 and Note 3 of the Notes to Consolidated Financial Statements included under “Item 8. Financial Statements and Supplementary Data” contained herein for additional information.

 

Plan of Reorganization

In accordance with the Plan, on the Effective Date, among other things:

 

The Predecessor transferred all of its assets and operations to the Successor, the Predecessor was dissolved and the Successor became the successor reporting company to the Predecessor pursuant to Rule 15d-5 of the Exchange Act;

 

The Successor issued (i) 9,500,000 new shares of its common stock, par value $0.01 per share (“common stock”), pro rata to holders of the 8.0% senior unsecured notes due April 2019 (the “Senior Notes”) with claims allowed under the Plan; (ii) 500,016 shares of common stock pro rata to holders of units of EVEP prior to the Effective Date; (iii) 800,000 warrants (the “Warrants”) to purchase 800,000 shares of common stock to holders of units of EVEP prior to the Effective Date exercisable for a five-year period commencing on the Effective Date entitling their holders upon exercise thereof, on a pro rata basis, to 8% of the total issued and outstanding common stock (including common stock as of the Effective Date issuable upon full exercise of the Warrants, but excluding any common stock issuable under the Company’s Management Incentive Plan (the “MIP”)), at a per share exercise price of $37.48; (iv) 79,000 shares of 8% Cumulative Nonparticipating Redeemable Series A Preferred Stock (the “Series A Preferred Stock”) to its indirectly wholly-owned subsidiary EV Midstream, L.P. for consideration of $790,000; and (v) 21,000 shares of Series A Preferred Stock to one employee of the Company and one employee of EnerVest for consideration of services to the Company, which vest on the earlier of (a) June 4, 2019 or (b) immediately prior to the consummation of a Sale Transaction as such term is defined in the Certificate of Designations, Preferences and Rights of the Series A Preferred Stock (the “Certificate of Designations”);

 

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

 

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

 

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

 

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

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

 

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

 

Predecessor and Successor Reporting

 

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

Our Operating Plan and Strategy

 

Our overall operating plan includes regular reviews of our asset base and cost structure to maximize cash flow. We continue to review strategic alternatives in order to maximize shareholder value. We are actively considering the potential divestiture of all of our remaining assets as well as a potential sale or merger of the Company. There can be no assurance that any such evaluations or reviews will result in one or more transactions or other strategic change or outcome.

 

We also focus our efforts on 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 workover and drilling operations.

 

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 2020.

 

Prices for oil, natural gas and natural gas liquids have significantly declined since December 31, 2019. These lower prices could affect our business in numerous ways, including, a negative impact on the Company’s revenues, earnings and cash flows in 2020 and future years and a decrease in proved reserves and possible impairments of the Company’s remaining oil and natural gas properties.

 

Our focus and efforts are impacted by depressed market conditions in early 2020. Crude oil has experienced near term downward pressure as a result of softer demand from the growing impact of the COVID-19 related crisis. Compounding the impact from COVID-19, at a meeting in Vienna on March 6, 2020, the alliance between Russia and OPEC on production cuts broke down as both sides were unable to reach an agreement over how much to restrict production in order to stabilize crude oil prices. As a result, Saudi Arabia subsequently announced that it would significantly increase production and cut the prices at which it sells crude oil. Those actions and the potential reactions by other oil exporting

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countries contributed to a sudden and precipitous drop in global crude prices. On April 12, 2020, the alliance between Russia and OPEC came to an agreement to reduce production and will reconvene on June 10, 2020 to determine whether further reductions are necessary. It is not clear at this point what impact these production cuts will have on global crude prices. We will continue to evaluate our operating plan and derivatives strategy in light of these events. 

 

Critical Accounting Policies

 

The discussion and analysis of our financial condition and results of operations is based upon the consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). The preparation of these consolidated financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosures about contingent assets and liabilities. Certain of our accounting policies involve estimates and assumptions to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions or if different assumptions had been used. We base these estimates and assumptions on historical experience and on various other information and assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions about future events and their effects cannot be perceived with certainty and, accordingly, these estimates may change as additional information is obtained, as more experience is acquired, as our operating environment changes and as new events occur.

 

Our critical accounting policies are important to the portrayal of both our financial condition and results of operations and require us to make difficult, subjective or complex assumptions or estimates about matters that are uncertain. We would report different amounts in our consolidated financial statements, which could be material, if we used different assumptions or estimates. We believe that the following are the critical accounting policies used in the preparation of our consolidated financial statements.

 

Bankruptcy Accounting

 

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

 

Upon emergence from bankruptcy on June 4, 2018, we elected to adopt and apply the relevant guidance provided in GAAP with respect to the accounting and financial statement disclosures for entities that have emerged from Chapter 11 (“fresh start accounting”) effective May 31, 2018 to coincide with the timing of our normal accounting period close. This process required us to make assumptions around valuations which included estimates of future prices, production costs, development expenditures, anticipated production, appropriate risk-adjusted discount rates and other relevant data. As a result of the application of fresh start accounting and the effects of the implementation of the plan of reorganization, the consolidated financial statements as of or after May 31, 2018, are not comparable with the consolidated financial statements prior to that date. To facilitate the financial statement presentations, we refer to the reorganized company in our consolidated financial statements as the “Successor” for periods subsequent to May 31, 2018 and “Predecessor” for periods prior to June 1, 2018. Furthermore, the consolidated financial statements have been presented with a “black line” division to delineate the lack of comparability between the Predecessor and Successor. 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.

 

Oil and Natural Gas Properties

 

We account for our oil and natural gas properties using the successful efforts method of accounting. Under this method, costs of productive exploratory wells, development dry holes and productive wells and undeveloped leases are capitalized. Oil and natural gas lease acquisition costs are also capitalized. Exploration costs, including personnel costs,

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certain geological and geophysical expenses and delay rentals for oil and natural gas leases, are charged to expense during the period the costs are incurred. Exploratory drilling costs are initially capitalized, but charged to expense if and when the well is determined not to have found reserves in commercial quantities.

 

Sales proceeds are credited to the carrying value of the properties, and no gains or losses are recognized upon the disposition of proved oil and natural gas properties except in transactions such as the significant disposition of an amortizable base that significantly affects the unit–of–production amortization rate.

 

The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as development or exploratory which will ultimately determine the proper accounting treatment of the costs incurred. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience. Wells may be completed that are assumed to be productive and actually deliver oil, natural gas and natural gas liquids in quantities insufficient to be economic, which may result in the abandonment of the wells at a later date. Wells are drilled that have targeted geologic structures that are both developmental and exploratory in nature, and an allocation of costs is required to properly account for the results. Delineation seismic incurred to select development locations within an oil and natural gas field is typically considered a development cost and capitalized, but often these seismic programs extend beyond the reserve area considered proved and management must estimate the portion of the seismic costs to expense. The evaluation of oil and natural gas leasehold acquisition costs requires managerial judgment to estimate the fair value of these costs with reference to drilling activity in a given area. Drilling activities in an area by other companies may also effectively condemn leasehold positions.

 

The successful efforts method of accounting can have a significant impact on the operational results reported when we are entering a new exploratory area in hopes of finding an oil and natural gas field that will be the focus of future developmental drilling activity. The initial exploratory wells may be unsuccessful and will be expensed. Seismic costs can be substantial which will result in additional exploration expenses when incurred.

 

We assess our proved oil and natural gas properties for possible impairment whenever events or circumstances indicate that the recorded carrying value of the properties may not be recoverable. Such events include a projection of future reserves that will be produced from a field, the timing of this future production, future costs to produce the oil, natural gas and natural gas liquids and future inflation levels. If the carrying amount of a property exceeds the sum of the estimated undiscounted future net cash flows, we recognize an impairment expense equal to the difference between the carrying value and the fair value of the property, which is estimated to be the expected present value of the future net cash flows. Estimated future net cash flows are based on existing reserves, forecasted production and cost information and management’s outlook of future commodity prices. Where probable and possible reserves exist, an appropriately risk adjusted amount of these reserves is included in the impairment evaluation. The underlying commodity prices used in the determination of our estimated future net cash flows are based on NYMEX forward strip prices at the end of the period, adjusted by field or area for estimated location and quality differentials, as well as other trends and factors that management believes will impact realizable prices. Future operating costs estimates, including appropriate escalators, are also developed based on a review of actual costs by field or area. Downward revisions in estimates of reserve quantities or expectations of falling commodity prices or rising operating costs could result in a reduction in undiscounted future cash flows and could indicate a property impairment.

 

Estimates of Oil, Natural Gas and Natural Gas Liquids Reserves

 

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 provide accurate forecasts. Non–producing reserve estimates for both developed and undeveloped properties were forecast using either volumetric and/or analogy

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methods. These methods provide accurate forecasts due to the mature nature of the properties targeted for development and an abundance of subsurface control data.

 

The accuracy of any reserve estimate is a function of the quality of available data, engineering and geological interpretation and judgment. For example, we must estimate the amount and timing of future operating costs, severance taxes, development costs and workover costs, all of which may vary considerably from actual results. In addition, as prices and cost levels change from year to year, the estimate of proved reserves also changes. Any significant variance in these assumptions could materially affect the estimated quantity and value of our reserves. Independent reserve engineers prepare our reserve estimates at the end of each year.

 

Despite the inherent imprecision in these engineering estimates, our reserves are used throughout our financial statements. For example, since we use the units–of–production method to amortize the costs of our oil and natural gas properties, the quantity of reserves could significantly impact our depreciation, depletion and amortization expense. Our reserves are also the basis of our supplemental oil and natural gas disclosures.

 

Revenue Recognition

 

Oil, natural gas and natural gas liquids revenues are recognized at a point in time upon the transfer of control of the products to a purchaser. We must use judgement and consider a variety of facts and circumstances to assess when transfer of control occurs, including but not limited to: whether the purchaser can direct the use of the hydrocarbon, the transfer of significant risks and rewards, our right to payment and transfer of legal title. Transfer of control typically occurs when the products are delivered to the purchaser, title or risk of loss has transferred and collectability of the revenue is reasonably assured. Revenue is recognized net of royalties due to third parties in an amount that reflects the consideration we expect to receive in exchange for those products. Virtually all of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of oil, natural gas and natural gas liquids and prevailing supply and demand conditions, so that prices fluctuate to remain competitive with other available suppliers.

 

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

 

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

 

RESULTS OF OPERATIONS

 

References to “Successor” relate to the financial position and results of operations of the reorganized Company subsequent to May 31, 2018, and references to “Predecessor” relate to the financial position and results of operations of the Company prior to, and including, May 31, 2018.

 

In addition to presenting Successor and Predecessor results of operations, in the table and discussion below, we have presented the Company’s operating results for the fiscal year ended December 31, 2018 on a combined basis (i.e., by combining the results of the applicable Predecessor and Successor periods). We believe that describing certain year-over-year variances and trends in our production, revenue and expenses for the year ended December 31, 2019 as compared to December 31, 2018 without regard to the concept of Successor and Predecessor (i.e., on a combined basis) facilitates a meaningful analysis of our results of operations and is useful in identifying current business trends. The combined results represent the sum of the reported amounts for the Predecessor period from January 1, 2018 through May 31, 2018 and the Successor period from June 1, 2018 through December 31, 2018. These combined results are not considered to be prepared in accordance with GAAP and have not been prepared as pro forma results under applicable regulations. The combined

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operating results may not reflect the actual results we would have achieved absent our emergence from bankruptcy and may not be indicative of future results.