Company Quick10K Filing
Rosehill Resources
Price1.95 EPS0
Shares53 P/E6
MCap104 P/FCF1
Net Debt366 EBIT33
TEV469 TEV/EBIT14
TTM 2019-09-30, in MM, except price, ratios
10-K 2019-12-31 Filed 2020-04-14
10-Q 2019-09-30 Filed 2019-11-07
10-Q 2019-06-30 Filed 2019-08-08
10-Q 2019-03-31 Filed 2019-05-15
10-K 2018-12-31 Filed 2019-03-29
10-Q 2018-09-30 Filed 2018-11-09
10-Q 2018-06-30 Filed 2018-08-14
10-Q 2018-03-31 Filed 2018-05-15
S-1 2018-02-14 Public Filing
10-K 2017-12-31 Filed 2018-04-17
10-Q 2017-09-30 Filed 2017-11-14
10-Q 2017-06-30 Filed 2017-08-15
10-Q 2017-03-31 Filed 2017-05-15
10-Q 2017-03-31 Filed 2017-05-15
10-K 2016-12-31 Filed 2017-02-27
10-Q 2016-09-30 Filed 2016-11-09
10-Q 2016-06-30 Filed 2016-08-09
10-Q 2016-03-31 Filed 2016-05-09
8-K 2020-06-12
8-K 2020-06-05
8-K 2020-05-29
8-K 2020-05-19
8-K 2020-05-14
8-K 2020-05-04
8-K 2020-04-14
8-K 2020-03-27
8-K 2020-03-25
8-K 2020-03-19
8-K 2019-11-07
8-K 2019-08-08
8-K 2019-06-07
8-K 2019-05-21
8-K 2019-05-14
8-K 2019-04-02
8-K 2019-03-27
8-K 2019-03-11
8-K 2018-11-08
8-K 2018-09-27
8-K 2018-09-24
8-K 2018-08-29
8-K 2018-08-13
8-K 2018-07-23
8-K 2018-05-22
8-K 2018-05-14
8-K 2018-05-02
8-K 2018-04-26
8-K 2018-04-17
8-K 2018-04-16
8-K 2018-03-28
8-K 2018-01-18
8-K 2018-01-03

ROSE 10K Annual Report

Part I
Item 1. Business
Item 1A. Risk Factors
Item 1B. Unresolved Staff Comments
Item 2. Properties
Item 3. Legal Proceedings
Item 4. Mine Safety Disclosures
Part II
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Item 6. Selected Financial Data
Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
Item 7A. Quantitative and Qualitative Disclosures About Market Risk
Item 8. Financial Statements and Supplementary Data
Note 1 - Organization and Basis of Presentation
Note 2 - Summary of Significant Accounting Policies and Recently Issued Accounting Standards
Note 3 - Subsequent Events and Liquidity
Note 4 - Earnings (Loss) per Share
Note 5 - Accounts Receivable
Note 6 - Derivative Instruments
Note 7 - Fair Value Measurements
Note 8 - Property and Equipment, Net
Note 9 - Asset Retirement Obligations
Note 10 - Accrued Liabilities and Other
Note 11 - Long - Term Debt, Net
Note 12 - 10% Series B Redeemable Preferred Stock
Note 13 - Income Taxes
Note 14 - Stockholders' Equity
Note 15 - Stock - Based Compensation
Note 16 - Transactions with Related Parties
Note 17 - Commitments and Contingencies
Note 18 - Revenue From Contracts with Customers
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
Item 9A. Internal Controls and Procedures.
Item 9B. Other Information
Part III
Item 10. Directors, Executive Officers and Corporate Governance
Item 11. Executive and Director Compensation
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
Item 13. Certain Relationships and Related Transactions, and Director Independence
Item 14. Principal Accounting Fees and Services
Part IV
Item 15. Exhibits and Financial Statement Schedules
Item 16. Form 10 - K Summary
EX-4.6 exhibit46123119.htm
EX-10.5 exhibit105123119.htm
EX-10.23 exhibit1023123119.htm
EX-10.27 exhibit1027123119.htm
EX-23.1 exhibit231consentofbdo.htm
EX-23.2 exhibit232consentofnsai.htm
EX-31.1 exhibit311123119.htm
EX-31.2 exhibit312123119.htm
EX-32.1 exhibit321123119.htm
EX-32.2 exhibit322123119.htm
EX-99.1 exhibit991123119.htm

Rosehill Resources Earnings 2019-12-31

Balance SheetIncome StatementCash Flow
87069652234817402015201620182020
Assets, Equity
85613713-11-352017201820192020
Rev, G Profit, Net Income
18511443-28-99-1702015201620182020
Ops, Inv, Fin

10-K 1 rose10-k12312019.htm 10-K Document

UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
FORM 10-K
 
ý    ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the fiscal year ended December 31, 2019
 
☐    TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
 
For the transition period from                to              
Commission file number: 001-37712
 
ROSEHILL RESOURCES INC.
(Exact Name of Registrant as Specified in its Charter)
 
Delaware
 
90-1184262
(State or Other Jurisdiction of Incorporation or Organization)
 
(IRS Employer Identification No.)
 
16200 Park Row, Suite 300
Houston, Texas 77084
(Address of principal executive offices)
 (281) 675-3400
 
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
Trading Symbol(s)
Name of each exchange on which registered
Class A Common Stock
ROSE
The Nasdaq Capital Market
Class A Common Stock Public Warrants
ROSEW
The Nasdaq Capital Market
Class A Common Stock Public Units
ROSEU
The Nasdaq Capital Market
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ý

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 ý

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 ý   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 ý   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
ý   
Smaller reporting company
ý
 
 
Emerging growth company
ý
 
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 Securities Exchange Act of 1934). Yes ☐ No ý




The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2019, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $39.9 million based on the last sales price of the shares as reported on the Nasdaq market on that date.

As of March 27, 2020, 28,811,078 shares of Class A common stock, par value $0.0001 per share, and 15,707,692 shares of Class B common stock, par value $0.0001 per share, were issued and outstanding.

Documents Incorporated by Reference

Portions of the Definitive Proxy Statement for the registrant’s 2020 Annual Meeting of Stockholders, filed with the commission on April 7, 2020, are incorporated by reference into Part III of this report.





ROSEHILL RESOURCES INC.
FORM 10-K FOR THE YEAR ENDED DECEMBER 31, 2019
 
TABLE OF CONTENTS
 
 
Page
PART I
 
 
ITEM 1.
ITEM 1A.
ITEM 1B.
ITEM 2.
ITEM 3.
ITEM 4.
PART II
 
 
ITEM 5.
ITEM 6.
ITEM 7.
ITEM 7A.
ITEM 8.
ITEM 9.
ITEM 9A.
ITEM 9B.
PART III
 
 
ITEM 10.
ITEM 11.
ITEM 12.
ITEM 13.
ITEM 14.
PART IV
 
 
ITEM 15.
ITEM 16.
 

1



GLOSSARY OF TERMS

The following are abbreviations and definitions of certain terms commonly used in the oil and natural gas industry and in this Annual Report on Form 10-K.

3-D seismic. Geophysical data that depict the subsurface strata in three dimensions. 3-D seismic typically provides a more detailed and accurate interpretation of the subsurface strata than 2-D, or two-dimensional, seismic.

Acquisition of properties. Costs incurred to purchase, lease or otherwise acquire a property, including costs of lease bonuses and options to purchase or lease properties, the portion of costs applicable to minerals when land including mineral rights is purchased in fee, brokers’ fees, recording fees, legal costs and other costs incurred in acquiring properties.

Basin. A large depression on the earth’s surface in which sediments accumulate.

Bbl. One stock tank barrel or 42 U.S. gallons liquid volume used in reference to crude oil or other liquid hydrocarbons.

Bbls/d. Barrels per day.

Boe. One barrel of oil equivalent determined using a ratio of six thousand cubic feet (Mcf) of natural gas being equivalent to one Bbl of crude oil, condensate or natural gas liquids.

Boe/d. Barrels of oil equivalent per day.

Btu. British thermal unit, which is the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit.

Completion. The process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency.

Condensate. Condensate is 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. For additional information, see the SEC’s definition in Rule 4-10(a)(4) of Regulation S-X, a link for which is available at the SEC’s website.

Crude oil. Liquid hydrocarbons retrieved from geological structures underground to be refined into fuel sources.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development costs. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.

Development project. A development project is the means by which petroleum resources are brought to the status of economically producible. As examples, the development of a single reservoir or field, an incremental development in a producing field, or the integrated development of a group of several fields and associated facilities with a common ownership may constitute a development project.

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.

Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality or location of oil or natural gas.

Dry hole or well. A well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production would exceed production expenses and taxes.

Economically producible. The term economically producible, as it relates to a resource, means a resource which generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation.

Exploitation. A development or other project which may target proven or unproven reserves (such as probable or possible reserves), but which generally has a lower risk than that associated with exploration projects.

2




Exploratory well. A well drilled to find and produce oil or natural gas reserves not classified as proved, to find a new reservoir in a field previously found to be productive of natural gas or oil in another reservoir or to extend a known 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.

Formation. A layer of rock that has distinct characteristics that differs from nearby rock.

Fracturing. The process of creating and preserving a fracture or system of fractures in a reservoir rock typically by injecting a fluid under pressure through a wellbore and into the targeted formation.

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

Henry Hub. A distribution hub of natural gas pipelines used as a benchmark in natural gas pricing and the underlying commodity of NYMEX natural gas futures contracts.

Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle with a specified interval.

Horizontal wells. Wells drilled directionally horizontal to allow for development of structures not reachable through traditional vertical drilling mechanisms.

Hydrocarbons. Oil, NGLs and natural gas are all collectively considered hydrocarbons.

Liquids. Natural gas that contains significant heavy hydrocarbons, such as ethane, propane, butane, pentane and isobutane.

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

MBoe. One thousand barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Mcf. One thousand cubic feet.

Mcf/d. One thousand cubic feet of natural gas per day.

Mineral interests. The interests in ownership of the resource and mineral rights, giving an owner the right to profit from the extracted resources.

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

MMBoe. One million barrels of crude oil equivalent, using a ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or NGLs.

MMBtu. One million British thermal units.

MMcf/d. One million cubic feet of natural gas per day

Net acres. The sum of the fractional working interest owned in gross acres.

Net production. Production that is owned by the Company less royalties and production due others.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

Net wells. The sum of the fractional working interest owned in gross wells.

NGLs. The combination of ethane, propane, butane, pentane and isobutane that when removed from natural gas become liquid under various levels of higher pressure and lower temperature.

3




NYMEX. New York Mercantile Exchange.

Oil. Crude oil and condensate.

Oil and natural gas properties. Tracts of land consisting of properties to be developed for oil and natural gas resource extraction.

Operating interest. An interest in natural gas and oil that is burdened with the cost of development and operation of the property.

Operator. The individual or company responsible for the exploration or production of an oil or natural gas well or lease.

Play. A set of discovered or prospective oil or natural gas accumulations sharing similar geologic, geographic and temporal properties, such as source rock, reservoir structure, timing, trapping mechanism and hydrocarbon type.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. A well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes.

Proved developed reserves. Reserves that can be expected to be recovered through: (i) 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; and (ii) through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Proved developed non-producing. Proved oil and natural gas reserves that are developed behind pipe or shut-in or that can be recovered through improved recovery only after the necessary equipment has been installed, or when the costs to do so are relatively minor. Shut-in reserves are expected to be recovered from (1) completion intervals which are open at the time of the estimate but which have not started producing, (2) wells that were shut-in for market conditions or pipeline connections, or (3) wells not capable of production for mechanical reasons. Behind-pipe reserves are expected to be recovered from zones in existing wells that will require additional completion work or future recompletion prior to the start of production.

Proved reserves. Proved oil and natural 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.

Proved undeveloped reserves (“PUDs”). Proved undeveloped oil and gas 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.

(i) Proved reserves on undrilled acreage shall be 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.

(ii) Proved undrilled locations can be classified as having undeveloped reserves 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.

(iii) Under no circumstances shall estimates for proved undeveloped reserves be attributable 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.

PV-10. When used with respect to natural gas, oil and NGL reserves, PV-10 means the present value of the estimated future net revenue to be generated from the production of proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date of the report or estimate, without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expense or to depreciation, depletion and amortization, discounted using an annual discount rate of 10%.  Also referred to as “present value.” After-tax PV-10 is also referred to as “standardized measure” and is net of future income tax expense.

4




Realized price. The cash market price less all expected quality, transportation and demand adjustments.

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

Reserves. Reserves are estimated remaining quantities of oil and natural 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 natural gas or related substances to the market and all permits and financing required to implement the project. Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

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.

Royalty interest. An interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development or operations.

SEC. United States Securities and Exchange Commission.

Spacing. The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing) and is often established by regulatory agencies.

Standardized measure. The present value of estimated future net revenues to be generated from the production of proved reserves, determined in accordance with assumptions required by the Financial Accounting Standards Board and the Securities and Exchange Commission (using current costs and the average annual prices based on the unweighted arithmetic average of the first-day-of-the-month price for each month) without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, and discounted using an annual discount rate of 10%. Federal income taxes have not been deducted from future production revenues in the calculation of standardized measure. In addition, Texas margin taxes and the federal income taxes associated with a corporate subsidiary have not been deducted from future production revenues in the calculation of the standardized measure as the impact of these taxes would not have a significant effect on the calculated standardized measure. Standardized measure does not give effect to commodity derivative transactions.

Tight formation. A formation with low permeability that produces natural gas with very low flow rates for long periods of time.

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 oil and natural gas regardless of whether such acreage contains proved reserves.

Undeveloped oil, natural gas and NGL reserves.  Undeveloped oil, natural gas and NGL reserves are 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.  Also referred to as “undeveloped reserves.”

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

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

West Texas Intermediate (“WTI”). A type of crude oil used as a benchmark in oil pricing and the underlying commodity of NYMEX oil futures contracts.


5



CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
 
This Annual Report on Form 10-K includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”) and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this report, including those regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management, are forward-looking statements. When used in this Annual Report on Form 10-K, the words “could,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described under “Risk Factors” in Item 1A of Part 1 of this Annual Report on Form 10-K. Such statements speak only as of the date of this report.

Forward-looking statements may include statements about:

our future financial performance;
our ability to realize the anticipated benefits of acquired mineral rights and other associated assets and interests in the Southern Delaware Basin in December 2017 (the “White Wolf Acquisition”);
our business strategy;
our reserves;
our liquidity and capital resources;
our ability to comply with covenants and obligations under our financing agreements;
the future of our operations;
our drilling prospects, inventories, projects and programs;
our ability to replace the reserves we produce through drilling and property acquisitions;
our financial strategy, liquidity and capital required for our development program;
our realized oil, natural gas and NGL prices;
the timing and amount of our future production of oil, natural gas and NGLs;
our hedging strategy and results;
our future drilling plans;
our expansion plans and future opportunities;
our competition and government regulations;
our ability to obtain permits and governmental approvals;
our pending legal or environmental matters;
our marketing of oil, natural gas and NGLs;
our leasehold or business acquisitions;
our costs of developing our properties;
general economic conditions;
credit markets;
the impact of the COVID-19 pandemic;
our ability to continue as a going concern;
our ability to successfully complete strategic initiatives, including potential refinancings, restructuring or deleveraging;
uncertainty regarding our future operating results; and
our plans, objectives, expectations and intentions contained in the Annual Report on Form 10-K that are not historical.

You should not place undue reliance on these forward-looking statements. These forward-looking statements are subject to a number of risks, uncertainties and assumptions, including but not limited to those risks described under “Risk Factors” in Item 1A of Part 1 of this Annual Report on Form 10-K. Moreover, we operate in a very competitive and rapidly changing environment. New risks emerge from time to time. It is not possible for our management to predict all risks, nor can we assess the impact of all factors on our business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements we may make.

Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.


6



Although we believe that our plans, intentions and expectations reflected in or suggested by the forward-looking statements we make in this Annual Report on Form 10-K are reasonable, we can give no assurance that these plans, intentions or expectations will be achieved or occur, and actual results could differ materially and adversely from those anticipated or implied by the forward-looking statements.

All forward-looking statements, expressed or implied, included in this Annual Report on Form 10-K are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report on Form 10-K.


7



PART I

ITEM 1. BUSINESS

Overview

Rosehill Resources Inc. (the “Company,” “Rosehill Resources,” “we,” “us,” or “our”) is an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and we divide our operations into two core areas: Northern Delaware Basin and the Southern Delaware Basin.

Our goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin. Our objective is to be a returns-oriented pure-play Delaware Basin company focusing on (i) acreage with reduced development risk as a result of being in proven areas within the vicinity of other successful wells, (ii) stacked pay zones, including Brushy Canyon, Upper Avalon, LowerAvalon/1st Bone Spring, 2nd Bone Spring Shale, 2nd Bone Spring Sand, 3rd Bone Spring Shale, 3rd Bone Spring Sand, Upper Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B and (iii) application of geology, optimizing well process improvements and well returns. We believe these characteristics have the potential to enhance our horizontal production capabilities, recoveries and economic results.

We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating Company, LLC (“Rosehill Operating”), an entity for which we act as the sole managing member and of whose common units we currently own approximately 64.5% (or 70.6% assuming the conversion of Rosehill Operating Series A preferred units into Rosehill Operating common units). As the sole managing member of Rosehill Operating, we, through our officers and directors, are responsible for all operational, management and administrative decisions relating to Rosehill Operating’s business without the approval of any other member, unless otherwise specified in the Second Amended and Restated Limited Liability Company Agreement of Rosehill Operating (the “Second Amended LLC Agreement”).

Presentation of Financial and Operating Data

On April 27, 2017, KLR Energy Acquisition Corporation (“KLRE”) acquired a portion of the equity interests of Rosehill Operating, an entity into which Tema Oil & Gas Company (“Tema”), a wholly owned subsidiary of Rosemore, Inc. (“Rosemore”), contributed certain assets and liabilities (the “Transaction”). Following the Transaction, KLRE changed its name to Rosehill Resources Inc. and became the sole managing member of Rosehill Operating. The consolidated financial statements included in this report were derived from the audited carve-out historical financial statements of Tema and reflects the operating results of Rosehill Operating for the periods up to the Transaction and the combined results of the Company and Rosehill Operating following the Transaction.

8



Organizational Structure

The following diagram illustrates the ownership structure of the company as of December 31, 2019:

ownershipchart2019.jpg

(1)
“Series B Preferred Stock Purchasers” refers to certain private funds and accounts managed by EIG Global Energy Partners, LLC.

(2)
“Company Affiliates” refers to KLR Energy Sponsor, LLC, KLR Group Investments, LLC and our current directors and officers.

(3)
Includes Class B Common Stock, Class A Common Stock, Series A Preferred Stock and warrants held by Tema.

(4)
The economic and voting interests set forth above do not take into account (i) the exercise of outstanding warrants for shares of Class A Common Stock, (ii) the future issuance of shares of Class A Common Stock under the Amended and Restated 2017 Long-Term Incentive Plan or (iii) the conversion of Series A Preferred Stock into shares of Class A Common Stock or the redemption of Rosehill Operating Common Units (and corresponding shares of Class B Common Stock) for shares of Class A Common Stock.

(5)
In connection with the conversion of our remaining Series A Preferred Stock into Class A Common Stock, the Rosehill Operating Series A Preferred Units owned by us will convert into Rosehill Operating Common Units and, on an as-converted basis, we will own approximately 71% of the Rosehill Operating Common Units.

Our Operations

We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all of our operations are conducted in the United States. Consequently, we currently report a single reportable segment. See the notes to our consolidated financial statements for financial information about this reportable segment. Our future development will be focused predominately on horizontal development drilling in our core acreage areas in the Delaware Basin.


9



Since 2012, we have drilled 89 gross horizontal wells in the Northern Delaware Basin and 17 gross horizontal wells in the Southern Delaware Basin. In 2019, our production was approximately 20,786 net Boe/d. As of December 31, 2019, our portfolio included 83 gross operated producing horizontal wells in the Northern Delaware Basin and 17 gross operated producing horizontal wells in the Southern Delaware Basin, as well as working interests in approximately 4,625 gross acres in the Northern Delaware Basin and 11,160 gross acres in the Southern Delaware Basin.

As of December 31, 2019, we have identified 605 gross operated potential horizontal drilling locations in the Northern and Southern Delaware Basin, including 48 locations associated with proved undeveloped reserves, in up to ten formations from Brushy Canyon down through the Wolfcamp B. As of December 31, 2019, we had 5 drilled uncompleted wells (“DUCs”).

Our locations

Historically, our horizontal drilling has been widespread across the majority of our lease acreage. We have established commercial production in eight distinct formations in the Northern Delaware Basin in the Upper Avalon, Lower Avalon, 2nd Bone Spring Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand, Upper Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B. In addition, offset operators have drilled and are producing in all ten formations, from Brushy Canyon down through the Wolfcamp B, enabling us to evaluate our acreage across various geographic areas and stratigraphic formations. As of December 31, 2019, approximately 77.7% of our total net operated acreage was either held by production or under continuous drilling provisions. Offset operator activity within the 2nd and 3rd Bone Spring Sands and the Wolfcamp formations as well as our recent successful Bone Spring and Wolfcamp drilling program has been a catalyst for our development program focused on the 2nd and 3rd Bone Spring Sands, Upper Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B formations in the Northern Delaware. If our development program recommences, our near-term development program in the Southern Delaware will focus largely on the 2nd Bone Spring and Wolfcamp A formations. We will closely monitor this offset activity and adjust our future development plans with information and best practices learned from other operators.
 
Based on our evaluation of applicable geologic and engineering data, we currently have approximately 605 gross (569 net) identified potential operated horizontal drilling locations in multiple horizons on our acreage. If we recommence our drilling program, we intend to continue to develop our reserves through development drilling and exploitation and exploration activities on this multi-year project inventory of identified potential drilling locations and through additional acquisitions that meet our strategic and financial objectives, targeting oil-weighted reserves.

Operational facilities

Historically, our development plan included the development of necessary infrastructure to lower our costs and support our drilling schedule. We expect to accomplish this goal primarily through contractual arrangements with third-party service providers. Our facilities are generally in close proximity to our well locations and include storage tank batteries, oil/natural gas/water separation equipment and artificial lift equipment. We have sufficient gathering systems and pipeline takeaway capacity to continue ongoing and planned operations. We have agreements in place with third-party natural gas and crude oil purchasers and processors to benefit from existing downstream infrastructure. We expect to continue to evaluate the marketplace to obtain additional transportation and gathering options and capacity in the form of new pipeline tie-ins.


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Major customers

We sell our production to a relatively small number of customers, as is customary in the industry. We sell all of our natural gas and NGLs under contracts with terms generally greater than twelve months and all of our oil under contracts with terms generally less than twelve months. The following table shows the percentage of sales to each of our major customers that accounted for 10% or more of our total oil, natural gas and NGL sales for each year presented.
 
Year Ended December 31,
 
2019
 
2018
 
2017
Customer
 
 
 
 
 
Major customer #1
63
%
 
17
%
 
%
Major customer #2
19

 
13

 

Major customer #3
12

 

 

Major customer #4

 
60

 
80

Major customer #5

 

 
10

Other
6

 
10

 
10

     Total
100
%
 
100
%
 
100
%

The loss of any one or all of our significant customers as a purchaser could materially and adversely affect our revenues.

The typical oil and natural gas lease agreement covering our properties provides for the payment of royalties to the mineral owner for all oil, NGLs and natural gas produced from any wells drilled on the leased premises. The lessor royalties and other leasehold burdens on our properties generally range from 12.5% to 25.0%, resulting in a net revenue interest to us generally ranging from 75.0% to 87.5%.

Gathering and Transportation

The majority of our crude oil production is sold at or near the lease as it enters third-party gathering pipelines and revenue is recognized based upon an index price less any applicable differentials. Because the majority of the purchasers of our crude oil production either owns or controls our crude oil production through the third-party pipelines used to transport our crude oil production, transportation costs related to moving our crude oil production are deducted from the price received.

Our natural gas production is sold at various delivery points to midstream processors and revenue is recognized based upon an appropriate index pricing for the extracted NGLs and remaining residue natural gas less applicable fees and differentials. If the midstream processor owns or controls our natural gas production through the gas gathering system that transports our natural gas production from the wellhead to the inlet of the midstream processor, transportation costs related to moving our natural gas production are deducted from the price received for our NGLs and residue gas. If the midstream processor takes possession of our natural gas production at the inlet to the midstream processor, transportation costs related to moving our natural gas production from the wellhead to the inlet of the midstream processor is recognized as transportation expense. We have long-term contracts in place to transport our natural gas production from the wellhead to various delivery points.

Competition

The oil and natural gas industry is intensely competitive and we compete with other companies that have greater resources. Many of these companies not only explore for and produce oil and natural gas, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies may be able to pay more for productive oil and natural gas properties and exploratory prospects or to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies may have a greater ability to continue exploration activities during periods of low oil and natural gas market prices. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial and human resources than many companies in our industry, we may be at a disadvantage in bidding for exploratory prospects and producing oil and natural gas properties.


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There is also competition between oil and natural gas producers and other industries producing energy and fuel, primarily based on price. Changes in the availability or price of oil and natural gas or other forms of energy, as well as business conditions, conservation and the ability to convert to alternate fuels and other forms of energy may affect the demand for oil and natural gas. Furthermore, competitive conditions may be substantially affected by various forms of energy legislation or regulation considered from time to time by the governments of the United States and the jurisdictions in which we operate. It is not possible to predict the nature of any such legislation or regulation that may ultimately be adopted or its effects upon our future operations. Such laws and regulations may substantially increase the costs of developing oil and natural gas and may prevent or delay the commencement or continuation of a given operation. Our larger competitors may be able to absorb the burden of existing and future federal, state and local laws and regulations more easily than we can, which would adversely affect our competitive position. Please see “Risk Factors - Risks Related to Our Operations - Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.”

Seasonality of business

Demand for oil and natural gas generally decreases during the spring and fall months and increases during the summer and winter months. However, seasonal anomalies such as mild winters or mild summers sometimes lessen this fluctuation. Weather conditions affect the demand for and prices of, oil, natural gas and NGLs. Due to these and other seasonal fluctuations, results of operations for quarterly periods may not be indicative of the results that may be realized on an annual basis. Such seasonal anomalies can also pose challenges for meeting our well drilling objectives and may increase competition for equipment, supplies and personnel during the spring and summer months, which could lead to shortages and increase costs or delay or temporarily halt our operations.

Operational hazards and insurance

The oil and natural gas industry involves a variety of operating risks, including, but not limited to, the risk of fire, explosions, blow outs, pipe failures and, in some cases, abnormally high-pressure formations which could lead to environmental hazards such as oil spills, natural gas leaks and the discharge of toxic gases. If any of these should occur, we could incur legal defense costs and could be required to pay amounts due to injury, loss of life, damage or destruction to property, natural resources and equipment, pollution or environmental damage, regulatory investigation and penalties and suspension of operations.

In accordance with what we believe to be 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 for certain property damages, control of well protection, commercial general liability, business automobile liability, workers compensation, excess umbrella liability and other coverages.

Our insurance is subject to exclusion and limitations, and there is no assurance that such coverage will fully or adequately protect us against liability from all potential consequences, damages and losses. Any of these operational hazards could cause a significant disruption to our business. A loss not fully covered by insurance could have a material adverse effect on our financial position, results of operations and cash flows. See Item 1A. “Risk Factors - Risks Related to Our Operations - We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or the insurance may be inadequate to protect us against, these risks.”

We reevaluate the purchase of insurance, policy terms and limits annually. Future insurance coverage for our 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 we believe 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 maintain minimal or no insurance coverage. We may not be able to secure additional insurance or bonding that might be required by new governmental regulations. This may cause us to restrict our operations, which might severely impact our financial position. The occurrence of a significant event, not fully insured against, could have a material adverse effect on our financial condition and results of operations.

Generally, we also require our third-party vendors to sign master service agreements in which they agree to indemnify us for injuries and deaths of the service provider’s employees as well as contractors and subcontractors hired by the service provider.


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Regulation of the Oil and Natural Gas Industry

Our operations are substantially affected by federal, state and local laws and regulations. Failure to comply with these laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impacts of compliance. Proposals and proceedings that could affect the oil and natural gas industry are regularly considered by the United States Congress (“Congress”), the states, the Federal Energy Regulatory Commission (“FERC”), the U.S. Environmental Protection Agency (“EPA”), other federal agencies and the courts. We cannot predict when or whether any such proposals may become effective. However, we do not believe that we would be affected by any such action materially differently than similarly situated competitors.

Regulation of oil and natural gas production

The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. We own property interests in jurisdictions that regulate drilling and operating activities by requiring, among other things, permits for the drilling of wells, bonding requirements to drill or operate wells, reports concerning operations and regulating the location of wells, the method of drilling and casing wells, the source and disposal of water used in the drilling and completion process, and the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. Our operations are also subject to various conservation laws and regulations, including the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area and the unitization or pooling of crude oil or natural gas wells, as well as regulations that limit or prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells. These laws also govern various conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density and plugging and abandonment of wells. The effect of these regulations may limit the amount of oil and natural gas that we can produce from our wells and limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, many jurisdictions impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within its jurisdiction. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.

Regulation of oil sales and transportation

Sales of oil, condensate and NGLs are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future. Our sales of oil are affected by the availability, terms and cost of transportation. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates interstate oil pipeline transportation rates under the Interstate Commerce Act. In general, interstate oil pipeline rates must be cost‑based, although settlement rates agreed to by all shippers are permitted and market based rates may be permitted in certain circumstances. Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated. In December 2015, H.R. 2029 was signed into law which lifted a ban on the export of crude oil from the United States. This will enable U.S. oil producers the flexibility to seek new markets and export oil into the global marketplace.

Regulation of natural gas sales and transportation

In the past, the federal government has regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future.

The transportation and sale for resale of natural gas in interstate commerce is regulated by FERC primarily under the Natural Gas Act of 1938, as amended (“NGA”) and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.


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The Energy Policy Act of 2005 (“EP Act of 2005”) amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior prescribed by FERC Pursuant to the EP Act of 2005, FERC promulgated regulations that make it unlawful to: (i) in connection with the purchase or sale of natural gas subject to the jurisdiction of FERC, or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, use, or employ any device, scheme, or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the Annual Reporting requirements described below.

The EP Act of 2005 also provided FERC with the power to assess civil penalties of up to $1,000,000 per day for violations of the NGA and increased FERC’s civil penalty authority under the NGA from $5,000 per violation per day to $1,000,000 per violation per day. Effective February 2019, to account for inflation, FERC’s civil penalty authority was increased to $1,269,500 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. Under FERC’s regulations, wholesale buyers and sellers of more than 2.2 million MMBtus of physical natural gas in the previous calendar year, including natural gas producers, gatherers and marketers, are now required to report, on May 1 of each year, aggregate volumes of natural gas purchased or sold at wholesale in the prior calendar year to the extent such transactions utilize, contribute to or may contribute to the formation of price indices, and whether they report prices to any index publishers, and if so, whether their reporting complies with FERC’s policy statement on price reporting.

Gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states onshore and in state waters. Section 1(b) of the NGA exempts natural gas gathering facilities from regulation by FERC under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain non-jurisdictional gathering facilities as jurisdictional transmission facilities, our costs of transporting gas to point of sale locations could increase. We believe that the third-party natural gas pipelines on which our gas is gathered meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation under the NGA. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of those gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.

For physical sales of these energy commodities, we are required to observe anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and under the Commodity Exchange Act (“CEA”) and regulations promulgated thereunder by the U.S. Commodity Futures Trading Commission. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce or futures or derivative contracts on such commodity. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity, as well as any manipulative or deceptive device or contrivance in connection with any contract of sale of any commodity in interstate commerce or futures or derivative contract on such commodity. Should we violate the anti-market manipulation laws and regulations, they could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.

Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship our natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenue we receive for sales of our natural gas.

Changes in law and to FERC or state policies and regulations may adversely affect the availability and reliability of firm or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect our operations in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.


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Regulation of Environmental and Occupational Safety and Health Matters

Our oil and natural gas exploration, development and production operations are subject to stringent federal, regional, state and local laws and regulations governing the discharge of materials into the environment or otherwise relating to occupational health and safety, or the protection of the environment and natural resources. Numerous federal, state and local governmental agencies, such as the EPA, issue regulations that often require difficult and costly compliance measures that carry substantial administrative, civil and criminal penalties and may result in injunctive obligations for non-compliance. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically or seismically sensitive areas and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or related to our owned or operated facilities. Liability under such laws and regulations is often strict (i.e., no showing of “fault” is required) and can be joint and several. 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, hydrocarbons or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. This trend, however, may not continue in the future.

Regulation of hazardous substances and waste handling

The Comprehensive Environmental Response, Compensation, and Liability Act of 1980 (“CERCLA”), also known as the “Superfund” law, and comparable state laws, impose liability without regard to fault or the legality of the original conduct, on certain classes of persons that are considered to have contributed to the release of a “hazardous substance” into the environment. These persons include the current and past owner or operator of the disposal site or the site where the release occurred and companies that disposed or arranged for the disposal of the hazardous substances at the site where the release occurred. Under CERCLA, such persons may be subject to joint and several strict liability for the costs of cleaning up the hazardous substances that have been released into the environment and for damages to natural resources. Although petroleum substances such as crude oil and natural gas are excluded from the definition of hazardous substances under CERCLA, various substances used in drilling and production operations are not covered by this exclusion and releases of these non-excluded substances or petroleum substances could give rise to CERCLA liability. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances or petroleum released into the environment. We are only able to directly control the operation of those wells for which we act as operator. Notwithstanding our lack of direct control over wells operated by others, the liability of an operator other than us for releases may, in certain circumstances, be attributed to us. We generate materials in the course of our operations that may be regulated as hazardous substances, but we are unaware of any liabilities for which we may be held responsible that would materially and adversely affect us.

The Resource Conservation and Recovery Act (“RCRA”) and analogous state laws impose detailed requirements for the generation, handling, storage, treatment and disposal of nonhazardous and hazardous solid wastes. RCRA specifically excludes drilling fluids, produced waters and other wastes associated with the development or production of crude oil, natural gas or geothermal energy from regulation as hazardous wastes. However, in the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics or are listed hazardous wastes. In addition, even wastes excluded from the definition of hazardous waste may be regulated by the EPA or state agencies under state laws or other federal laws. Moreover, it is possible that those particular oil and natural gas development and production wastes now excluded from the definition of hazardous wastes could be classified as hazardous wastes in the future. For example, from time to time various environmental groups have challenged the EPA’s exclusion of certain oil and gas wastes from regulations RCRA. In one such challenge, the U.S. District Court for the District of Columbia entered a consent decree requiring EPA to evaluate the exclusion of oil and gas wastes, and by March 2019, to either sign a notice of proposed rulemaking revising the regulations excluding oil and gas wastes or sign a determination that revision of the exclusion is not necessary. In April 2019, the EPA concluded that revisions to RCRA was not necessary the time. A loss of the RCRA exclusion for drilling fluids, produced waters and related wastes, if the EPA were to eliminate the exclusion, could result in an increase in our costs to manage and dispose of generated wastes, which could have a material adverse effect on our results of operations and financial position. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.


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We currently own, lease, or operate numerous properties that have been used for oil and natural gas development and production activities for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for recycling or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property, or performance of remedial plugging or pit closure operations to prevent future contamination.

Regulation of water discharges

The Clean Water Act and comparable state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced waters and other oil and natural gas wastes, into or near navigable waters. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. The discharge of dredge and fill material into regulated waters, including wetlands, is also prohibited, unless authorized by a permit issued by the U.S. Army Corps of Engineers (the “Corps”). In September 2015, the EPA and the Corps issued new rules defining the scope of the EPA’s and the Corps’ jurisdiction under the Clean Water Act with respect to certain types of waterbodies and classifying these waterbodies as regulated wetlands. However, in October 2019, the EPA and the Corps published a final rule to repeal the 2015 rule and recodified the jurisdiction to that which existed under the Clean Water Act prior to the 2015 rule; this final rule became effective in December and is currently subject to litigation which challenges the repeal. In January 2020, the EPA finalized a replacement rule clarifying the scope of regulated waters which widely is viewed as less expansive then the 2015 rule; the rule will be effective 60 days after publication in the Federal Register and is likely to be subject to legal challenges. As a result of these recent developments, the final determination of the scope of the EPA’s and the Corp’s jurisdiction is uncertain. To the extent any revised rule expands the scope of the Clean Water Act’s jurisdiction, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. Obtaining permits has the potential to delay the development of oil and natural gas projects. These laws and any implementing regulations provide for administrative, civil and criminal penalties for any unauthorized discharges of pollutants in reportable quantities and may impose substantial potential liability for the costs of removal, remediation and damages.

In addition, pursuant to these laws and regulations, we may be required to obtain and maintain approvals or permits for the discharge of wastewater or storm water and are required to develop and implement spill prevention, control and countermeasure plans, also referred to as “SPCC plans,” for on-site storage of significant quantities of oil. We believe that we maintain all required discharge permits necessary to conduct our operations and further believe we are in substantial compliance with the terms thereof.

The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (“OPA”), which amends and augments the 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 waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies 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, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.

Regulation of air emissions

The federal Clean Air Act and comparable state laws restrict the emission of air pollutants from many sources, such as, for example, compressor stations, through air emissions standards, construction and operating permitting programs and the imposition of other compliance requirements. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. Over the next several years, we may be required to incur certain capital expenditures for air pollution control equipment or other air emissions related issues. For example, in October 2015, the EPA lowered the National Ambient Air Quality Standards (“NAAQS”) for ozone from 75 to 70 parts per billion. In November 2017, the EPA published a list of areas that are in compliance with the new ozone standard and, separately in December 2017, issued responses to state recommendations for designating non-attainment areas. States had the opportunity to submit new air quality monitoring to the EPA prior to the EPA finalizing its non-attainment designations. The EPA issued final attainment status designations in April 2018 and July 2018. State implementation of the revised

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NAAQS could result in stricter permitting requirements or could delay or limit our ability to obtain such permits and result in increased expenditures for pollution control equipment, the costs of which could be significant.

In addition, the EPA has adopted new rules under the Clean Air Act that require the reduction of volatile organic compound emissions from certain fractured and refractured natural gas wells for which well completion operations are conducted and further require that most wells use reduced emission completions, also known as “green completions.” These regulations also establish specific new requirements regarding emissions from production-related wet seal and reciprocating compressors, and from pneumatic controllers and storage vessels. More recently, in June 2016, the EPA finalized rules regarding criteria for aggregating multiple small surface sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities, on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting processes and requirements. Compliance with these and other air pollution control and permitting requirements has the potential to delay the development of oil and natural gas projects and increase our costs of development, which costs could be significant. However, we do not believe that compliance with such requirements will have a material adverse effect on our operations.

Regulation of greenhouse gas emissions (“GHG”)

In response to findings that emissions of carbon dioxide, methane and other GHG present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the federal Clean Air Act that, among other things, require preconstruction and operating permits for GHG emissions from certain large stationary sources that otherwise require such permits for non-GHG emissions. Facilities required to obtain preconstruction permits for their GHG emissions are also required to meet “best available control technology” standards that are being established by the states or, in some cases, by the EPA on a case-by-case basis. These regulatory requirements could adversely affect our operations and restrict or delay our ability to obtain air permits for new or modified sources. In addition, the EPA has adopted rules requiring the monitoring and reporting of GHG emissions from specified onshore and offshore oil and natural gas production sources in the United States on an annual basis, which include certain of our operations. Furthermore, in June 2016, the EPA finalized rules that establish new controls for emissions of methane from new, modified or reconstructed sources in the oil and natural gas source category (the “2016 NSPS Rules”), including production, processing, transmission and storage activities. The rule includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions. In September 2018, the EPA proposed amendments to the 2016 rules that would reduce the 2016 rules’ fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other changes and is in
the process of finalizing the targeted amendments. Separately, on August 28, 2019, the EPA proposed amendments to the NSPS Rules which would remove all sources in the transmission and storage segment of the oil and natural gas industry from regulation under the rules and rescind the methane requirements in the 2016 rules that apply to sources in the production and processing segments of the industry. As an alternative, EPA also is proposing to rescind the methane requirements that apply to all sources in the oil and natural gas industry, without removing any sources from the current source category. Various industry and environmental groups have separately challenged the 2016 NSPS rules and the proposed revisions to the rules will likely be subject to legal challenge after finalization. As a result of these developments, future implementation of the standards is uncertain at this time. To the extent implemented, compliance with these rules would require enhanced record-keeping practices, the purchase of new equipment such as optical gas imaging instruments to detect leaks and increased frequency of maintenance and repair activities to address emissions leakage. The rules would also likely require hiring additional personnel to support these activities or the engagement of third-party contractors to assist with and verify compliance. New rules related to the reduction of methane and other GHG emissions could result in increased compliance costs on our operations.

There have not been significant legislative proposals to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of state and regional programs and initiatives have been enacted or are being considered that are aimed at tracking or reducing GHG emissions by means of cap and trade programs, direct taxation of carbon emissions, or that promote the use of less carbon-intensive fuels. These programs typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. At the international level, the United States joined the international community at the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change in Paris, France (“Paris Agreement”) that requires member countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals every five years beginning in 2020. The Paris Agreement entered into force in November 2016. Although this agreement does not create any binding obligations for nations to limit their GHG emissions, it does include pledges from participating nations to voluntarily limit or reduce future emissions. In June 2017, President Trump stated that the United States would withdraw from the Paris Agreement, but may enter into a future international agreement related to GHGs. The Paris Agreement provides for a four-year exit process beginning when it took effect in November 2016 and a formal withdrawal could not begin until three years after the Paris Agreement went into effect. In November 2019, the United States began the process to withdraw from the Paris Agreement by submitting formal notifications to the United Nations but the withdrawal will not take effect until one year from delivery of the notification,which would result in an effective

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exit date of November 2020. The United States’ adherence to the exit process is uncertain or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations 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. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. Our operations are onshore and not located in coastal or flood-prone regions of the United States, but if any such effects were to occur at our locations, these effects have the potential to cause physical damage to our assets or affect the availability of water for our operations and thus could have a material adverse effect on our operations.

Regulation of hydraulic fracturing

Hydraulic fracturing is an important common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process, which involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production, is typically regulated by state oil and natural gas commissions. However, legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act (“SDWA”) to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has recently taken the position that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. Also, in June 2016, the EPA published a final rule prohibiting the discharge of wastewater from onshore unconventional oil and gas extraction facilities to publicly owned wastewater treatment plants.

The EPA has issued final regulations under the federal Clean Air Act that establish air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package includes New Source Performance Standards to address emissions of sulfur dioxide and volatile organic compounds and a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. These rules require a 95% reduction in volatile organic compounds emitted from these activities by requiring the use of reduced emission completions or “green completions” on new hydraulically-fractured wells. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These standards, as well as any future laws and their implementing regulations, may require us to obtain pre-approval for the expansion or modification of existing facilities or the construction of new facilities expected to produce air emissions, impose stringent air permit requirements, or mandate the use of specific equipment or technologies to control emissions.

The EPA has also released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events.


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Several states, including Texas, and local jurisdictions, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards or require the disclosure of the composition of hydraulic fracturing fluids. For example, the Texas Railroad Commission has adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. The Texas Railroad Commission has also adopted disposal well rule amendments designed, among other things, to require applicants for new disposal wells that will receive non-hazardous produced water and hydraulic fracturing flowback fluid to conduct seismic activity searches utilizing the U.S. Geological Survey. The searches are intended to determine the potential for earthquakes within a circular area of 100 square miles around a proposed new disposal well. The disposal well rule amendments also clarify the Texas Railroad Commission’s authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The Texas Railroad Commission has used this authority to deny permits for waste disposal wells.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations that specific chemicals used in the fracturing process could adversely affect groundwater. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

ESA and migratory birds

The Endangered Species Act (“ESA”) and (in some cases) comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered or proposed for listing are known to exist. The U.S. Fish and Wildlife Service may designate critical habitat and suitable habitat areas that it believes are necessary for survival of a threatened or endangered species. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and may materially delay or prohibit land access for oil and natural gas development. Moreover, as a result of a settlement approved by the U.S. District Court for the District of Columbia in September 2011, the U.S. Fish and Wildlife Service was required to make a determination on listing of more than 250 species as endangered or threatened under the ESA by no later than completion of the Agency’s 2017 fiscal year. The agency missed this deadline and continues to review species for listing under the ESA. Also, in the past, the federal government has issued indictments under the Migratory Bird Treaty Act to several oil and natural gas companies after dead migratory birds were found near reserve pits associated with drilling activities. However, in December 2017, the Department of Interior issued a new opinion revoking its prior enforcement policy and concluded that an incidental take is not a violation of the Migratory Bird Treaty Act. The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures or could result in limitations on our development activities that could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as a critical or suitable habitat, it could adversely impact the value of our leases.

OSHA

We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, the OSHA hazard communication standard, the Emergency Planning and Community Right-to-Know Act and comparable state statutes and any implementing regulations require that we organize or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.


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Related Permits and Authorizations

Many environmental laws require us to obtain permits or other authorizations from state or federal agencies before initiating certain drilling, construction, production, operation, or other oil and natural gas activities and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal, or litigation, which, in certain cases, can delay or halt projects and cease production or operation of wells, pipelines and other operations.

Employees

As of December 31, 2019, we had 89 full-time employees. None of our employees are represented by labor unions or covered by collective bargaining agreements, and we have not experienced any strikes or work stoppages. In light of the ongoing impact of current uncertainty in the global markets and commodity prices, the Company announced on March 19, 2020 that it halted drilling and completions activity and announced on March 27, 2020 that it eliminated 52 full-time employee positions.

Offices

Our principal executive offices are located at 16200 Park Row, Suite 300, Houston, Texas 77084, and our telephone number at that address is (281) 675-3400. We also have office space in Midland, Texas.

Available information

We are required to file quarterly and annual reports, current reports, proxy statements and other information with the SEC. You may read and copy any documents filed by us with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. Our filings with the SEC are also available to the public at the SEC’s website at http://www.sec.gov. Our Class A Common Stock is listed and traded on the Nasdaq Capital Market under the symbol “ROSE.”

We also make available on our website (http://www.rosehillresources.com) all documents that we file with the SEC, free of charge, as soon as reasonably practicable after we electronically file such material with the SEC. Our Code of Ethics and Corporate Governance Guidelines and the charters of our audit committee, compensation committee and nominating and governance committee are also available on our website and in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our corporate offices at 16200 Park Row, Suite 300, Houston, Texas 77084. Information contained on our website is not incorporated by reference into this Annual Report on Form 10-K. We intend to disclose on our website any amendments or waivers to our Code of Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K.

ITEM 1A. RISK FACTORS

The nature of our business activities subjects us to certain risks as discussed in this report. These risks and uncertainties are not the only ones we face. Additional risks and uncertainties presently unknown to us or currently deemed immaterial also may impair our business operations. The occurrence of one or more of these risks or uncertainties could materially and adversely affect our business, our financial condition, our cash flows and the results of our operations, which in turn could negatively impact the value of our securities.

Risks Related to Our Operations

The Company may be adversely affected by the recent decrease in demand and oversupply of oil and natural gas as a result of the coronavirus pandemic and actions by Saudi Arabia and Russia.

The spread of the COVID-19 coronavirus has caused severe disruptions in the worldwide economy, including the global demand for oil and natural gas, the movement of people and services in the United States and the visibility into future conditions, which could in turn disrupt our business and operations. Moreover, recent actions by Saudi Arabia and Russia have caused a worldwide oversupply in oil and natural gas. The continued spread of the COVID-19 coronavirus, related government and other restrictions and oversupply of oil and natural gas are expected to result in a significant decrease in business or cause our oil and natural gas purchasers to be unable to meet existing payment or other obligations to us, including the ability to purchase produced oil, natural gas, and NGLs from us. In mid-March, we suspended all drilling and completion programs. We do not currently have plans to recommence the program. The loss of any one or all of our significant customers as a purchaser could materially and adversely affect our revenues and may require us to shut-in a portion or all of our wells. In such an event, restarting our wells may require significant cost, and we cannot guarantee that we would be able to restart at the same level. Moreover, due to the unprecedented nature of the current pandemic and market conditions, we are unable to predict the degree or duration of any adverse impact on our operations and financial condition and other risks described in this report may be enhanced by such conditions.

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Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition, cash flows and results of operations and our ability to meet our capital expenditure obligations and financial commitments and result in an impairment on the value of our assets.

Our revenues, profitability, cash flows and future growth, as well as liquidity and ability to access additional sources of capital, depends substantially on prevailing prices for oil, natural gas and NGLs. A reduction in or sustained lower prices will reduce the amount of oil, natural gas and NGLs that we can economically produce and may result in impairments of our proved reserves or reduction of our proved undeveloped reserves. Oil, natural gas and NGL prices also affect the amount of cash flow available for capital expenditures and ability to borrow and raise additional capital.

The markets for oil, natural gas and NGLs have historically been volatile and recently reached multi-year low levels. For example, since 2014, the WTI spot price for oil declined from a high of $107.95 per barrel in June 2014 to a low of $26.19 per barrel in February 2016 and was $61.14 per barrel on December 31, 2019 and $21.84 on March 27, 2020. The NYMEX Henry Hub spot price for natural gas declined from a high of $8.15 per MMBtu in February 2014 to a low of $1.49 per MMBtu in March 2016 and ended at $2.09 per MMBtu on December 31, 2019. Likewise, NGLs, which are made up of ethane, propane, isobutane, normal butane and natural gasoline, each of which have different uses and different pricing characteristics, have been volatile.

The market prices for oil, natural gas and NGLs depend on factors beyond our control. Some, but not all, of the factors that can cause fluctuation include:

worldwide and regional economic conditions impacting the global supply and demand for oil, natural gas and
NGLs;

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

political and economic conditions in, or affecting, other producing regions or countries, including the Middle East, Africa, South America and Russia;

actions of the Organization of the Petroleum Exporting Countries (“OPEC”), its members and other state-controlled oil companies, including the ability of members of OPEC and other state controlled oil companies to agree to and maintain price and production controls;

the level of global exploration, development and production;

the level of global inventories;

the extent to which U.S. shale producers become “swing producers” adding or subtracting to the world supply;

prevailing prices on local price indexes in the area in which we operate;

the proximity, capacity, cost and availability of gathering and transportation facilities;

localized and global supply and demand fundamentals and transportation availability;

the cost of exploring for, developing, producing and transporting reserves;

weather conditions, other natural disasters and climate change;

world health events, including the COVID-19 pandemic, and their related impact on the economy and demand for oil and gas;

technological advances affecting energy consumption;

the price and availability of alternative fuels;

worldwide conservation measures;

domestic and foreign governmental relations, regulation and taxes;

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worldwide governmental regulation and taxes;

U.S. and foreign trade restrictions, regulations, tariffs, agreements and treaties;

the level and effect of trading in commodity futures markets, including commodity price speculators and others;

political conditions or hostilities and unrest in oil producing regions; and

market perceptions of future prices, whether due to the foregoing factors or others.

Lower commodity prices will reduce our cash flows and borrowing ability and have caused us to cease our development program in March 2020. We may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in the present value of our reserves and our ability to develop future reserves. Lower commodity prices may also reduce the amount of oil, natural gas and NGLs that we can produce economically and may impact our ability to satisfy our water disposal agreement.

Using lower prices in estimating proved reserves would likely result in a reduction in proved reserve volumes due to economic limits. While it is difficult to project future economic conditions and whether such conditions will result in impairment of proved property costs, we consider several variables including specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors. Current 2020 forward pricing will more than likely result in impairments of our properties during the first quarter of 2020 and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity, or ability to finance planned capital expenditures. Lower oil, natural gas and NGL prices may also result in a reduction in the borrowing base under our Amended and Restated Credit Agreement, which may be redetermined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders.

Because we have elected to suspend our drilling program in light of recent market conditions and commodity prices, we expect to be unable to continue to hold certain leases that are scheduled to expire, which will further reduce our reserves. As a result, a substantial or extended decline in commodity prices is expected to materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

Concerns over economic, business or industry conditions may have a material adverse effect on our results of operations, liquidity and financial condition.

Concerns over global economic conditions, energy costs, geopolitical issues (include price wars between Saudi Arabia and Russia), inflation, the availability and cost of credit, the decline in the European, Asian and the United States financial markets and the COVID-19 pandemic have contributed to increased economic uncertainty and diminished expectations for the global economy. In addition, continued hostilities in the Middle East and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy. Concerns about global economic growth have had a significant adverse impact on global financial markets and commodity prices. If the economic climate in the United States or abroad deteriorates, worldwide demand for petroleum products could diminish further, which could impact the price at which we can sell our production, affect the ability of our vendors, suppliers and customers to continue operations and ultimately adversely impact our results of operations, liquidity and financial condition.

Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.

The oil and natural gas industry is capital-intensive. We have historically made substantial capital expenditures related to development and acquisition projects. We expect to fund our capital expenditures with cash generated by operations and, if needed, borrowings under the Company’s Amended and Restated Credit Agreement, dated as of March 28, 2018, by and among Rosehill Operating, Rosehill and JPMorgan Chase Bank, N.A., as administrative agent and issuing bank, and each of the lenders from time to time party thereto (the “Amended and Restated Credit Agreement”). However, as of March 19, 2020, we had no availability under the Amended and Restated Credit Agreement. Any financing needs may require an alteration or increase in our capitalization substantially through the issuance of debt or equity or the sale of assets. Our current debt and preferred equity securities require that a substantial portion of the cash flow from our operations be used for the payment of interest and dividends, thereby reducing our ability to use cash flow from operations to fund working capital, capital expenditures and acquisitions. The issuance of additional equity securities may not be an available source of capital under current conditions and would be dilutive to stockholders. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other

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things: oil, natural gas and NGL prices; actual drilling results; the availability and cost of drilling rigs and other services and equipment; and regulatory, technological and competitive developments.

If cash flow from operations or available borrowings under our Amended and Restated Credit Agreement decrease as a result of lower oil, natural gas and NGL prices, operational difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain operations at current levels. If additional capital is needed, we may not be able to obtain financing on acceptable terms, if at all. If cash flow from operations or available under existing or anticipated credit facilities are insufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of the development of our properties, which in turn could lead to a decline in our reserves and production and could materially and adversely affect our business, financial condition and results of operations. Please read “ - Risks Related to Our Indebtedness.”

Drilling for oil and natural gas involves numerous and significant risks and uncertainties.

Risks that we face while drilling wells or maintaining producing wells include:

effects of weather, floods, snowstorms, ice storms and similar natural conditions, on the drilling location and
delivery of materials to the wellsite;

unforeseen water flows;

lost circulation of drilling fluids;

unexpected oil and gas flows into the wellbore;

drill pipe, casing and equipment failure, or loss of equipment in the well;

failure or inaccuracies of directional drilling measurement devices;

excessive hole washouts in the salt/anhydrite zones resulting in poor surface cement jobs;

inability to reach the desired drilling zone with conventional bits and drilling techniques;

failure to land a wellbore in the desired drilling zone;

inability to stay in the desired drilling zone or being able to run tools and other equipment consistently while drilling horizontally through the formation; and

difficulties in running casing the entire length of the wellbore.

Risks that we face while completing wells include:

the ability to fracture stimulate the planned number of stages;

the ability to run tools the entire length of the wellbore during completion operations; and

the ability to successfully clean out the wellbore after completion of the final fracture stimulation stage.

In addition, certain of the new techniques we have adopted may cause irregularities or interruptions in production due to offset wells being shut in and the time required to drill and complete multiple wells before any such wells begin producing. Furthermore, the results of our drilling that we may complete in new or emerging formations are more uncertain initially than drilling results in areas that are more developed and have a longer history of established production. Newer or emerging formations and areas have limited or no production history and, consequently, we are more limited in assessing future drilling results in these areas. If we recommence our drilling program and our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and a decline in the value of our undeveloped acreage.

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Costs and uncertainties associated with drilling, completing, and operating wells could adversely affect our business, financial condition or results of operations.

Our future financial condition and results of operations will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control. On March 19, 2020, we announced that we halted future drilling and completions activity, which is expected to negatively impact our financial condition, results of operations and anticipated production.

Other factors may curtail, delay or cancel our operations, production and future drilling projects, including the following:

delays imposed by or resulting from compliance with regulatory requirements, including limitations resulting from wastewater disposal, emissions of GHGs and limitations on hydraulic fracturing;

pressure or irregularities in geological formations;

shortages of or delays in obtaining equipment and qualified personnel, including as a result of the COVID-19 outbreak;

shortages or delays in obtaining water for hydraulic fracturing activities;

equipment failures, accidents or other unexpected operational events;

lack of available gathering facilities or delays in construction of gathering facilities;

lack of available capacity on interconnecting transmission pipelines;

adverse weather conditions, including such conditions which are possibly connected to climate change;

drought conditions limiting the availability of water for hydraulic fracturing, including such conditions as possibly connected to climate change;

issues related to compliance with environmental regulations, including protections for threatened or endangered species;

environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;

declines in oil and natural gas prices;

limited availability of financing at acceptable terms;

title problems; and

limitations in the market for oil and natural gas.

Hedging transactions may limit our potential gains and increase our potential losses.

In order to manage our exposure to price risks in the marketing of our oil, natural gas and natural gas liquids production, we have entered into oil, natural gas and natural gas liquids price hedging arrangements with respect to a portion of our anticipated production and we may enter into additional hedging transactions in the future. While intended to reduce the effects of volatile commodity prices, such transactions may limit our potential gains and increase our potential losses if commodity prices were to rise substantially over the price established by the hedge. In addition, such transactions may expose us to the risk of loss in certain circumstances, including instances in which:

our production is less than expected;

there is a widening of price differentials between delivery points for our production; or

the counterparties to our hedging agreements fail to perform under the contracts.

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The adoption of derivatives legislation by Congress could have an adverse impact on our ability to use derivative instruments to reduce the effects of commodity prices, interest rates and other risks associated with our business.

Historically, we have entered into a number of commodity derivative contracts in order to hedge a portion of our oil and natural gas production. The Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, requires the SEC and the Commodity Futures Trading Commission (“CFTC”), along with other federal agencies, to promulgate regulations implementing the new legislation.

The CFTC has finalized other regulations implementing the Dodd-Frank Act’s provisions regarding trade reporting, margin, clearing and trade execution; however, some regulations remain to be finalized and it is not possible at this time to predict when the CFTC will adopt final rules. For example, the CFTC has re-proposed regulations setting position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents. Certain bona fide hedging transactions are expected to be made exempt from these limits. Also, it is possible that under recently adopted margin rules, some registered swap dealers may require us to post initial and variation margins in connection with certain swaps not subject to central clearing.

The Dodd-Frank Act and any additional implementing regulations could significantly increase the cost of some commodity derivative contracts (including through requirements to post collateral, which could adversely affect our available liquidity), materially alter the terms of some commodity derivative contracts, limit our ability to trade some derivatives to hedge risks, reduce the availability of some derivatives to protect against risks we encounter and reduce our ability to monetize or restructure our existing commodity derivative contracts. If we reduce our use of derivatives as a consequence, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Increased volatility may make us less attractive to certain types of investors. Finally, the Dodd-Frank Act was intended, in part, to reduce the volatility of oil and natural gas prices, which some legislators attributed to speculative trading in derivatives and commodity instruments related to oil and natural gas. If the implementing regulations result in lower commodity prices, our revenues could be adversely affected. Any of these consequences could adversely affect our business, financial condition and results of operations.

Our derivative activities could result in financial losses or could reduce our earnings.

A portion of our oil and natural gas production has historically been hedged in order to protect cash flow from falling prices; however, in our three-way collars, we are not protected against falling prices once prices fall below our sold put options. The use of these arrangements limits our ability to benefit from increases in the prices of natural gas and oil. As of December 31, 2019, we had open commodity derivative contracts for the months of January 2020 through December 2022 covering a total of 10.5 million barrels of oil and 4.9 million MMBtus of natural gas. We also had crude oil basis swaps covering a total of 15.0 million barrels of oil and natural gas basis swaps covering a total of 2.1 million MMBtus of natural gas. Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our commodity derivative.

A portion of our outstanding borrowings under our Amended and Restated Credit Agreement has been hedged in order to protect cash flow from rising interest rates. As of December 31, 2019, we had interest rate swaps covering a total of $150,000,000 of our outstanding borrowings under our Amended and Restated Credit Agreement at a fixed rate of 1.721%. Accordingly, our reported interest expense may fluctuate significantly as a result of changes in fair value of our interest rate derivatives.

Commodity or interest rate derivatives may also expose us to the risk of financial loss in some circumstances, including when:

production and sales are insufficient to offset losses under the commodity derivatives;

the counterparty to the derivatives defaults on its contractual obligations;

there is an increase in the differential between the underlying price in the derivative contracts and actual prices received;

issues arise with regard to legal enforceability of such instruments; or

applicable laws or regulations regarding such instruments are changed.

The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivatives that require cash collateral, particularly if commodity prices or interest rates change in a manner averse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make

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payments on our indebtedness, and which could also limit the size of our borrowing base. Future collateral requirements will depend on arrangements with counterparties, highly volatile oil and natural gas prices and interest rates. In addition, commodity derivatives could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.

Our derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.

Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.

The process of estimating oil and natural gas reserves is complex. It requires interpretations of available technical data and many assumptions, including assumptions relating to current and future economic conditions and commodity prices. Any significant inaccuracies in these interpretations or assumptions could materially affect the estimated quantities and present value of our reserves. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. In addition, because we have suspended our development program, we expect to experience a reduction in proved undeveloped reserves in 2020. Any significant variance could materially affect the estimated quantities and present value of our reserves.

You should not assume that the present value of future net revenues from our estimated reserves is the current market value of such reserves. In accordance with SEC requirements, we generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate, particularly when commodity prices decline after the date of estimate.

Selection of drilling locations is susceptible to uncertainties that could materially alter the occurrence or timing of our drilling.

On March 19, 2020, we announced that we halted our drilling program in light of recent deteriorating global markets and commodity prices. If we resume drilling, our ability to drill and develop these locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors. Because of these uncertain factors, we do not know if the potential drilling locations our management identifies will ever be drilled or if we will be able to produce oil or natural gas in commercial qualities from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.

Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.

As of December 31, 2019, approximately 77.7% of our total net acreage was either held by production or under continuous drilling provisions. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. If our leases expire and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations on the necessary timeline depends on a number of uncertainties, some of which are beyond our control, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations,

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gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals. On March 19, 2020, we announced a halt in our drilling program. We lost 321 net acres during the first quarter of 2020 and estimate that we will lose approximately 2,638 net acres in the remainder of 2020 if we do not resume drilling during 2020.

Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.

Water is an essential component of deep shale oil and natural gas drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led governmental authorities to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. If we are unable to obtain water to use in our operations, we may be unable to economically produce oil and natural gas, which could have a material and adverse effect on our financial condition, results of operations and cash flows.

All of our producing properties are located in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas, making us vulnerable to risks associated with operating in a single geographic area.

All of our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, in West Texas. At December 31, 2019, 100% of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or NGLs.

In addition to the geographic concentration of our producing properties in the Delaware Basin described above, at December 31, 2019, approximately 65% percent of our proved reserves were attributable to the 2nd Bone Spring Sand, Wolfcamp A (X/Y) and Lower Wolfcamp A formations. This concentration of assets within a small number of producing horizons exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.

Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.

Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we recommence our drilling program and conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future cash flow and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace the current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations would be materially and adversely affected.

We will not be the operator on all of our acreage or drilling locations, and, therefore, we will not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated assets.

As of December 31, 2019, we have leased or acquired approximately 13,219 net acres in the Delaware Basin, approximately 97.2% of which we operate. As of December 31, 2019, we have identified 605 gross horizontal drilling locations. We expect to operate approximately 96.9% of, and have an approximate 96.7% working interest in, the acreage we own in the Southern Delaware Basin and believe that the acreage may be prospective for six different shale formations. We will have limited ability to exercise influence over the operations of the drilling locations we do not operate, and the operators of those locations may at any time have economic, business or legal interests or goals that are inconsistent with us. Furthermore, the success and timing of development activities by such operators will depend on a number of factors that will be largely outside of our control, including:

the timing and amount of capital expenditures;

 
the operator’s expertise and financial resources;

the approval of other participants in drilling wells;

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the selection of technology; and

the rate of production of reserves, if any.

This limited ability to exercise control over the operations and associated costs of some of our non-operated drilling locations could prevent the realization of targeted returns on capital in drilling or acquisition activities.

We participate in oil and gas leases with third parties who may not be able to fulfill their commitments to our projects.

We own less than 100% of the working interest on a minority of the oil and gas leases on which we conduct operations, and other unrelated parties own the remaining portion of the working interest. Financial risks are inherent in any operation where the cost of drilling, equipping, completing and operating wells is shared by more than one person. We could potentially be held liable for joint activity obligations of other working interest owners, such as nonpayment of costs and liabilities arising from the actions of other working interest owners. In addition, declines in oil, natural gas and NGL prices may increase the likelihood that some of these working interest owners, particularly those that are smaller and less established, are not able to fulfill their joint activity obligations. Other working interest owners may be unable or unwilling to pay their share of project costs, and, in some cases, may declare bankruptcy. In the event any other working interest owners do not pay their share of such costs, we would likely have to pay those costs, and may be unsuccessful in any efforts to recover these costs from other working interest owners, which could materially adversely affect our financial position.

The marketability of our production will be dependent upon transportation and other facilities, certain of which we will not control. If these facilities are unavailable, our operations could be interrupted and our revenues reduced.

The marketability of our oil and natural gas production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. For further discussion on our gathering and transportation processes, see “Business – Gathering and Transportation.”

We entered into crude oil gathering and natural gas gathering agreements with Gateway, for production from our Loving County wells, that will expire in April 2027. We do not control Gateway’s or the third-party’s transportation and processing facilities and our access to the facilities may be limited or denied. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or a significant disruption in the availability of third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil and natural gas and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements or encounter production related difficulties, we may be required to shut in or curtail production or flare natural gas. Any such shut-in, curtailment, or flaring or an inability to obtain favorable terms for delivery of the oil and natural gas produced from our fields, would materially and adversely affect our financial condition and results of operations.

Multi-well pad drilling may result in volatility in our operating results.

We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling can delay the commencement of production. In addition, problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results. due to timing, as well as declines in oil and gas prices. Furthermore, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.

Prolonged decreases in our drilling program may require us to pay certain non-use fees or impact our ability to comply with certain contractual requirements.

In March 2020, commodity prices dropped significantly and we announced a halt in our drilling program. Due to the nature of our drilling programs and the oil and natural gas industry in general, we are a party to certain agreements that require us to meet various contractual obligations or require us to utilize a certain amount of goods or services, including, but not limited to, water commitments, throughput volume commitments and power commitments. The continued cessation of our drilling activity and production levels could, in turn, require us to pay for unutilized goods or services or impact our ability to meet these contractual obligations and may result in lease expirations.

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We may incur losses as a result of title defects in the properties in which we invest.

The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we have historically obtained title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property and may be required to pay damages to the actual owner of the lease.

The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than currently anticipated. Therefore, our estimated PUDs may not be ultimately developed or produced.

As of December 31, 2019, 42.0% of our total estimated proved reserves were classified as PUDs. Development of these PUDS may take longer and require higher levels of capital expenditures than currently anticipated. Delays in the development of our PUDs, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves if we no longer believe with reasonable certainty that we will develop the PUDs within five years after their initial booking according to the SEC’s reserve rules. If we do not drill our PUD wells within five years after their respective dates of booking, we may be required to write-down our PUDs. At this time we have no plans to develop our PUDs.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take impairments or write-downs of the carrying values of our properties.

Accounting rules require periodic review of the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. We did not record any impairments to proved property for the years ended December 31, 2019 and 2018. Impairment expense for the year ended December 31, 2017 was $1.1 million. However, commodity prices have declined significantly in recent years and lower commodity prices in the future could result in impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken. Current 2020 forward pricing will more than likely result in impairments of our properties during the first quarter of 2020.

Conservation measures and technological advances could reduce demand for oil and natural gas.

Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. The impact of the changing demand for oil and natural gas may have a material adverse effect on our business, financial condition, results of operations and cash flows.

We depend upon significant purchasers for the sale of most of our oil, natural gas and NGL production.

We have historically sold our production to a relatively small number of customers, as is customary in our business. For the year ended December 31, 2019 and 2018, three customers accounted for approximately 94% and 90%, respectively, of our total revenue. During such periods, no other purchaser accounted for 10% or more of our revenue. The loss of any one or all of our significant customers as a purchaser could materially and adversely affect our revenues. We may not be able to replace such revenue in a timely manner or at all. Furthermore, any non-payment or non-performance by our customers may have a negative impact on our results of operations and cash flows.

Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.

Our operations are subject to stringent and complex federal, state and local laws and regulations governing the discharge of materials into the environment, occupational health and safety aspects of our operations, or otherwise relating to the protection of the environment and natural resources. These laws and regulations may impose numerous obligations applicable to our operations, including but not limited to the acquisition of a permit or other approval before conducting regulated activities; the restriction of the types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; restrictions on drilling activities intended to protect certain species of wildlife or their habitat that may adversely affect our ability to conduct drilling

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activities in certain areas; the application of specific health and safety criteria addressing worker protection; or the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA, the U.S. Fish and Wildlife Service, U.S. Army Corps. of Engineers and analogous state environmental and wildlife protection agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions may require us to perform difficult and costly compliance measures or corrective actions. A critical habitat or suitable habitat designation could result in further material restrictions to federal land use and private land use and could delay or prohibit land access or oil and gas development. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations and the issuance of orders limiting or prohibiting some or all of our operations; and plugging and abandonment responsibilities for wells which have ceased producing. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.

Certain environmental laws impose strict as well as joint and several liabilities for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been released into the environment. We may be required to remediate contaminated properties currently or formerly operated by us or our predecessors in interest or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. The trend has been for more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry, resulting in increased costs of doing business and consequently affecting profitability. For further discussion, see “Business –Regulation of Environmental and Occupational Safety and Health Matters.”

We may incur substantial losses and be subject to substantial liability claims as a result of our operations. Additionally, we may not be insured for, or the insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations.

Our exploration and development activities are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

environmental hazards, such as uncontrollable releases of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater and air contamination;

abnormally pressured formations;

mechanical difficulties, such as stuck oilfield drilling and service tools and drill pipe or casing failures or collapse;

fire, explosions and ruptures of pipelines;

 
personal injuries and death;

natural disasters, which may include severe weather as possibly connected to climate change and seismic events as possibly connected to injection of produced water and flowback into disposal wells; and

terrorist attacks targeting oil and natural gas related facilities and infrastructure.

Any of these risks could adversely affect our ability to conduct operations or result in substantial loss to us as a result of claims for:

injury or loss of life;

damage to and destruction of property, natural resources and equipment;

pollution and other environmental damage;

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statutory or regulatory investigations and penalties; and

repair and remediation costs.

We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, statutory and regulatory penalties, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.

Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.

If we decide to resume our drilling program, properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or to be economically viable. The use of micro-seismic data and other technologies and the study of producing fields and data from other wells in the same area, or more fully explored prospects, will not enable us to know conclusively prior to drilling whether oil or natural gas will be present or, if present, in commercial quantities. Further, any future drilling operations may be curtailed, delayed or cancelled as a result of numerous factors, including:

unexpected or adverse drilling conditions;

title problems;

elevated pressure or lost circulation in formations;

equipment failures or accidents;

adverse weather conditions;

compliance with environmental and other governmental or contractual requirements; and

increase in the cost of, shortages or delays in the availability of, electricity, supplies, materials, drilling or workover rigs, equipment and services.

We may be unable to make attractive acquisitions or successfully integrate acquired assets or businesses, and any inability to do so may disrupt our business and hinder our ability to grow.

In the future, we may make acquisitions of assets or businesses that complement or expand our current business. However, there is no guarantee we will be able to identify attractive acquisition opportunities. In the event we are able to identify attractive acquisition opportunities, we may not be able to complete the acquisition or do so on commercially acceptable terms. Competition for acquisitions may also increase the cost of, or cause us to refrain from, completing acquisitions.
 

The success of any completed acquisition will depend on our ability to integrate effectively the acquired assets or business. The process of integrating acquired assets or businesses may involve unforeseen difficulties and may require a disproportionate amount of managerial and financial resources. In addition, possible future acquisitions may be larger and for purchase prices significantly higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. We may incur significant additional indebtedness or restrictive financing to fund the purchase price and other costs associated with acquisitions. We may not realize expected benefits from our acquisitions or acquired properties may lose value following the acquisition, such as the White Wolf Acquisition completed in 2017, which was financed with proceeds from our Second Lien Notes and Series B Preferred Stock. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations, which may cause the market price of our Class A Common Stock to decline.


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In addition, our Amended and Restated Credit Agreement, Certificate of Designation for the Series B Preferred Stock filed with the Secretary of State of the State of Delaware on December 8, 2017 (“Series B Certificate of Designation”) and the Note Purchase Agreement, dated as of December 8, 2017 (as amended by the Limited Consent and First Amendment to the Note Purchase Agreement, dated as of March 28, 2018, the “Note Purchase Agreement”) impose, and future debt agreements may impose, among other things, limitations on our ability to enter into mergers or combination transactions. Such limitations may also restrict our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of assets or businesses. On March 19, 2020, we announced that we had drawn the remaining available borrowings under our Amended and Restated Credit Agreement, which could significantly limit our ability to incur additional indebtedness.
 
We may be subject to risks in connection with acquisitions of properties.

The successful acquisition of properties requires an assessment of several factors, including:

recoverable reserves;

future oil and natural gas prices and their applicable differentials;

geological risks;

access to markets;

operating costs; and

potential environmental and other liabilities.

The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. However, these reviews will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems.

Certain of our properties are subject to land use restrictions, which could limit the manner in which we conduct our business.

In order to bring equipment, supplies, water, personnel and produced products to and from certain of our properties, we or our contractors must obtain permissions or rights-of-way from other parties, including private property owners and governmental agencies. There is no guarantee that we or our contractors will be able to obtain or continue to obtain those permissions or rights or to obtain them at a reasonable cost. In addition, certain of our properties are subject to land use restrictions, including ordinances, which could limit the manner in which we conduct our business. Although none of our proposed drilling locations associated with proved undeveloped reserves as of December 31, 2019 are on properties currently subject to such land use restrictions, such restrictions may become effective in the future. All of the permissions, rights-of-way and restrictions discussed above could affect, among other things, our access to and the permissible uses of our facilities as well as the manner in which we produce oil and natural gas and may restrict or prohibit drilling in general. The costs incurred to comply with such restrictions may be significant in nature, and we may experience delays or curtailment in the pursuit of development activities and may even be precluded from the drilling of wells.
 

The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute future development plans within our budget and on a timely basis.

We do not own any drilling rigs, nor do we own other equipment and supplies that are critical to our continuing ability to drill for and produce oil, gas and NGLs. We are dependent on access to qualified and competent contractors for such equipment and supplies, as well as the personnel to engage in our drilling and production program. The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with oil and natural gas prices, causing periodic shortages. Our operations are concentrated in areas in which industry has increased rapidly, and as a result, demand for such drilling rigs, equipment and personnel, as well as access to transportation, processing and refining facilities in these areas, has increased, as have the costs for those items. We may not be able to renew or obtain new drilling contracts for rigs whose contracts are expiring or are terminated or obtain drilling contracts for our uncontracted

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new builds. Any delay or inability to secure the personnel, including frac crews, equipment, power, services, resources and facilities access necessary for us to increase our development activities could result in production volumes being below our forecasted volumes. In addition, any such negative effect on production volumes, or significant increases in costs, could have a material adverse effect on our cash flow and profitability. Furthermore, if we are unable to secure a sufficient number of drilling rigs at reasonable costs, we may not be able to drill all of our acreage before our leases expire.

We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.

Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Decreased levels of drilling activity in the oil and gas industry in recent periods have led to declining costs of some drilling equipment, materials and supplies. However, such costs may rise faster than increases in our revenue if commodity prices rise, thereby negatively impacting our profitability, cash flow and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our prior or future commodity derivative activities.

Climate change laws and regulations restricting emissions of GHGs could result in increased operating costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.

There have not been significant legislative proposals to reduce GHG emissions at the federal level in recent years. In the absence of such federal climate legislation, a number of federal, state and regional regulations, programs and initiatives have been enacted or are being considered that are aimed at tracking or reducing GHG emissions by means of cap and trade programs, direct taxation of carbon emissions, or that promote the use of less carbon-intensive fuels.

Although it is not possible at this time to predict how legislation or new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations 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. Substantial limitations on GHG emissions could adversely affect demand for the oil and natural gas we produce and lower the value of our reserves. Recently, activists concerned about the potential effects of climate change have directed their attention at sources of funding for fossil-fuel energy companies, which has resulted in certain financial institutions, funds and other sources of capital restricting or eliminating their investment in oil and natural gas activities. Ultimately, this could make it more difficult to secure funding for exploration and production activities. In addition, increasing attention to climate change risks has resulted in an increased possibility of governmental investigations and additional private litigation against fossil-fuel energy companies without regard to causation or our contribution to the asserted damage, which could adversely affect our business. Notwithstanding potential risks related to climate change, the International Energy Agency estimates that global energy demand will continue to rise and will not peak until after 2040 and that oil and gas will continue to represent a substantial percentage of global energy use over that time. Finally, it should be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other climatic events. Our operations are onshore and not located in coastal or flood-prone regions of the United States, but if any such effects were to occur, they have the potential to cause physical damage to our assets or affect the availability of water for our operations and thus could have a material adverse effect on our operations. For further discussion on climate change laws and regulations restricting emissions of GHGs, see “Business – Regulation of Environmental and Occupational Safety and Health Matters.”

Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.

Hydraulic fracturing is an important and common practice that is used to stimulate production of oil or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations and expect to continue that practice. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the federal SDWA over certain hydraulic fracturing activities. For further discussion on regulation of hydraulic fracturing, see “Business – Regulation of the Oil and Natural Gas Industry.” At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad

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Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule includes testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. If new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
 

Legislation or regulatory initiatives restrict our ability to dispose of produced water, including saltwater, gathered from such activities, which could have a material adverse effect on our business.

We dispose of large volumes of produced water, including saltwater, gathered from our drilling and production operations using disposal wells pursuant to permits issued by governmental authorities overseeing such disposal activities and pursuant to permissions granted by the owners of properties where the disposal wells are located. While these permits are issued in accordance with existing laws and regulations, these legal requirements are subject to change, as are the permissions granted by property owners. Any changes could result in the imposition of more stringent operating constraints or new monitoring and reporting requirements, owing to, among other things, concerns of the public or governmental authorities or property owners regarding such gathering or disposal activities. The adoption and implementation of any new laws or regulations or changes that restrict our expected ability to use hydraulic fracturing or dispose of produced water gathered from our drilling and production activities, either by limiting disposal volumes, disposal well locations or otherwise, or requiring us to shut down disposal wells, could have a material adverse effect on our business, financial condition and results of operations. For example, In 2015, the United States Geological Survey identified eight states, including Texas, with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. In addition, a number of lawsuits have been filed in other states, for example recent lawsuits in Oklahoma, alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. In response to these concerns, regulators in some states are seeking to impose additional requirements, including requirements on the permitting of produced water disposal wells or otherwise to assess any relationship between seismicity and the use of such wells. For example, in October 2014, the Railroad Commission of Texas published a rule governing permitting or re-permitting of disposal wells that would require, among other things, the submission of information on seismic events occurring within a specified radius of the disposal well location, as well as logs, geologic cross sections and structure maps relating to the disposal area in question. If the permittee or an applicant for a disposal well permit fails to demonstrate that the saltwater or other fluids are confined to the disposal zone or if scientific data indicates that such a disposal well is likely to be or determined to be contributing to seismic activity, then the agency may deny, modify, suspend or terminate the permit application or existing operating permit for that well. The Oklahoma Corporation Commission also released well completion seismicity guidelines in December 2016 for operators in the SCOOP and STACK that call for hydraulic fracturing operations to be suspended following earthquakes of certain magnitudes in the vicinity. In addition, in February 2017, the Oklahoma Corporation Commission’s Oil and Gas Conservation Division issued an order limiting future increases in the volume of oil and natural gas wastewater injected into the ground in an effort to reduce the number of earthquakes in the state. It is possible that similar measures could be implemented in the areas where we operate.

Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil or natural gas and secure trained personnel.

Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. Many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. Those companies may be able to pay more for productive properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, other companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost to attract and retain qualified personnel may increase substantially in the future. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital, which could have a material adverse effect on our business.


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The loss of senior management or technical personnel could adversely affect our operations.

We depend on the services of our senior management and technical personnel, and our ability to hire and retain them is important to our continued success and growth. We do not maintain, nor do we plan to obtain, any insurance against the loss of any of these individuals. Loss of the services of our senior management or technical personnel could have a material adverse effect on our business, financial condition and results of operations. On March 27, 2020, we announced that we terminated 52 full-time employees, including a number of senior management and technical personnel. We cannot guarantee that we will be able to replace these individuals if and when we resume drilling and completion activity.

We identified material weaknesses in our internal control over financial reporting in the past and may identify additional material weaknesses in the future or otherwise fail to maintain an effective system of internal controls, which may result in material misstatements of our financial statements or cause us to fail to meet our periodic reporting obligations.

We are required to comply with certain provisions of Section 404 of the Sarbanes-Oxley Act of 2002 (“Sarbanes-Oxley Act”). Section 404 requires that we document and test our internal control over financial reporting and issue management’s assessment of our internal control over financial reporting. In our quarterly report for the quarter ended March 31, 2019, we identified and disclosed a material weakness related to the accuracy of our accounting for income taxes which led to the incorrect application of U.S. GAAP, and ineffective controls over the financial statement close and reporting processes related to income taxes. To remediate the material weakness, we have made improvements to our internal controls over income taxes that strengthen the quality of our internal review. Based on these improvements and testing performed by management, we believe the implemented controls are operating effectively and the material weakness has been remediated as of December 31, 2019.

If we fail to comply with the requirements of Section 404 of the Sarbanes-Oxley Act, the accuracy and timeliness of the filing of our annual and quarterly reports may be materially adversely affected and could cause investors to lose confidence in our reported financial information, which could have a negative effect on the trading price of our Class A Common Stock. In addition, a material weakness in the effectiveness of our internal control over financial reporting could reduce our ability to obtain financing and require additional expenditures to comply with these requirements, each of which could have a material adverse effect on our business, results of operations and financial condition.

Our disposition activities may be subject to factors beyond our control, and in certain cases we may retain unforeseen liabilities for certain matters.

We have regularly sold non-core assets in order to increase capital resources available for other core assets and to create organizational and operational efficiencies. We have also occasionally sold interests in core assets for the purpose of accelerating the development and increasing efficiencies in such core assets. Various factors could materially affect our ability to dispose of such assets in the future, including the approvals of governmental agencies or third parties and the availability of purchasers willing to acquire the assets with terms we deem acceptable.
 
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.

The standardized measure of our estimated proved reserves and our PV-10 are not necessarily the same as the current market value of our estimated proved oil, natural gas and NGL reserves.

The present value of future net cash flow from our proved reserves, or standardized measure, and our related PV-10 calculation, may not represent the current market value of our estimated proved oil, natural gas and NGL reserves. In accordance with SEC requirements, we base the estimated discounted future net cash flow from our estimated proved reserves on the 12-month average prices, calculated as the unweighted arithmetic average for the first-day-of-the-month price for each month and costs in effect as of the date of the estimate, holding the prices and costs constant throughout the life of the properties. Actual future prices and costs may differ materially from those used in the net present value estimate, and future net present value estimates using then current prices and costs may be significantly less than current estimates. In addition, the 10% discount factor we use when calculating discounted future net cash flow for reporting requirements in compliance with the Financial Accounting Standard Board Codification 932, “Extractive Activities-Oil and Gas,” 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.

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Our ability to use net operating loss carryforwards to offset future taxable income for U.S. federal income tax purposes is subject to limitation.

As of December 31, 2019, we have approximately $31.3 million of U.S. federal operating loss carryforwards (“NOLs”), which will begin to expire in 2037. Utilization of these NOLs depends on many factors, including our future income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income when a corporation has undergone an “ownership change” (as determined under Section 382 of the Code). An ownership change generally occurs if one or more shareholders (or a group of shareholders) who are each deemed to own at least 5% of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage during a rolling three-year period.

In the event of an ownership change, utilization of our NOLs in existence at the time of the ownership change would be subject to an annual limitation, determined by multiplying the value of our stock at the time of the ownership change by the applicable long-term tax-exempt rate, subject to certain adjustments. Any unused annual limitation may be carried over to later years until they expire.

We believe we experienced an ownership change as a result of the Transaction on April 27, 2017, and our NOLs at the time of the Transaction are subject to limitation under Section 382 of the Code, which may cause U.S. federal income taxes to be paid earlier than otherwise would be paid if such limitation were not in effect and could cause such NOLs to expire unused, in each case reducing or eliminating the benefit of such NOLs. To the extent we are not able to offset our future income with our NOLs or carry back our NOLs to offset income in prior tax years, this would adversely affect our operating results and cash flows if we attain profitability. Similar rules and limitations may apply for state income tax purposes.

We depend on computer and telecommunications systems and failures in our systems or cyber security attacks could significantly disrupt our business operations.

Our business has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We have entered into agreements with third parties for hardware, software, telecommunications and other information technology services in connection with our business. In addition, we have developed proprietary software systems, management techniques and other information technologies incorporating software licensed from third parties. We depend on digital technology, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data, analyze seismic and drilling information, conduct reservoir modeling and reserves estimation, communicate with employees and business associates, perform compliance reporting and in many other activities related to our business. Our business associates, including vendors, service providers, purchasers of our production and financial institutions, are also dependent on digital technology.

As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks and those of our business associates may become the target of cyber-attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.

It is possible we could incur interruptions from cyber security attacks, computer viruses or malware. We believe that we have positive relations with our related business associates, including vendors, and maintain adequate anti-virus and malware software and controls; however, any interruptions to our arrangements with third parties to our computing and communications infrastructure or our information systems could significantly disrupt our business operations. A cyber-attack involving our information systems and related infrastructure, or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, 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. Furthermore, any failures in our systems or cyber security attacks may increase the costs for insurance, recovery, remediation, potential litigation and other security measures, and some insurance coverage may become more difficult to obtain, if available at all.

Our derivative transactions expose us to counterparty credit risk.

Our derivative transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract and we may not be able to realize the benefit of the derivative contract.


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Changes to federal or state tax laws or elimination of federal income tax deductions currently available with respect to oil and natural gas exploration and development could cause us to have a greater tax expense.

Currently, many states conform their calculation of corporate taxable income to the calculation of corporate taxable income at the U.S. federal level. However, states may change or modify the calculation of corporate taxable income or cause taxes to be payable at the operating entity level. Any resulting increase in taxable income due to such changes could have an adverse effect on our financial position, results of operations and cash flows.

From time to time, U.S. lawmakers have proposed certain significant changes to U.S. tax laws applicable to oil and natural gas companies. These changes include, but are not limited to: (i) the elimination of current deductions for intangible drilling and development costs; (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. It is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes were to be enacted, as well as any similar changes in state law, it could eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.

Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil and natural gas.

Negative public perception regarding us or our industry could have an adverse effect on our operations.

Negative public perception regarding us or our industry resulting from, among other things, concerns raised by advocacy groups about hydraulic fracturing, seismicity, oil spills and explosions of natural gas transmission lines, may lead to regulatory scrutiny, which may, in turn, lead to new state and federal safety and environmental laws, regulations, guidelines and enforcement interpretations. These actions may cause operational delays or restrictions, increased operating costs, additional regulatory burdens and increased risk of litigation. Moreover, governmental authorities exercise considerable discretion in the timing and scope of permit issuance and the public may engage in the permitting process, including through intervention in the courts. Negative public perception could cause the permits we need to conduct our operations to be withheld, delayed, or burdened by requirements that restrict our ability to profitably conduct our business.

Risks Related to Our Indebtedness

We may not be able to service our debt and pay dividends on our preferred stock, which may result in forced repayment or redemption or events of default. We may seek restructuring or protection under Chapter 11 of the Bankruptcy Code.

We have a significant amount of indebtedness, including borrowings under our Amended and Restated Credit Agreement and $100 million aggregate principal amount of 10.00% Senior Secured Second Lien Notes issued on December 8, 2017 (the “Second Lien Notes”). We are also required to make cash dividend payments on our Series B Preferred Stock. Our payment obligations under our Amended and Restated Credit Agreement, Series B Preferred Stock and Second Lien Notes were approximately $38.2 million for the year ended December 31, 2019. Our ability to make scheduled payments on, or to refinance, our indebtedness obligations, including our Amended and Restated Credit Agreement and $100 million aggregate principal amount of 10% Senior Secured Second Lien Notes issued on December 8, 2017 (the “Second Lien Notes”), depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our current and future indebtedness.

Our Amended and Restated Credit Agreement restricts our cash distributions to an amount not to exceed $8.0 million and $25.0 million on our Series A Preferred Stock and Series B Preferred Stock, respectively, in any fiscal year. Such distributions can only be made so long as both before and immediately following such distributions, (i) we are not in default, (ii) our unused borrowing capacity is equal to or greater than 20% of the committed borrowing capacity and (iii) our ratio of Total Debt to EBITDAX is not greater than 3.5 to 1.0. On March 19, 2020, we announced that we drew the remaining available borrowings under our Amended and Restated Credit Agreement. Accordingly, we will be unable to pay cash dividends on our Series A Preferred Stock and Series B Preferred Stock until we repay borrowings to 80% or less of capacity. If we fail to pay dividends on the Series B Preferred Stock in any fiscal quarter, the dividend rate will increase from 10% to 12% per annum on the $1,000 liquidation preference per share of Series B Preferred Stock until such dividends are paid in full. We do not expect to pay dividends on the Series B Preferred Stock with respect to at least the first quarter of 2020. In addition, if the Company fails to pay dividends for three out of four consecutive fiscal quarters or for six quarters (whether or not consecutive), then a representative appointed by

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the holders of a majority of the outstanding shares of Series B Preferred Stock has the right to appoint one director to our board of directors, and we are required to seek the approval of such representative for certain corporate actions (such as the incurrence of indebtedness exceeding 3.25x, the approval of any applicable company budget and any capital expenditures in excess of $500,000), in each case, until three months following the date on which such dividends are paid in full. Failure to pay cash dividends on the Series B Preferred for nine months or more could give the holders the right to require the Company redeem the Series B Preferred Stock for cash.

If our cash flows and capital resources are insufficient to fund debt or preferred stock service obligations, we may be forced to further reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Certain of these actions require the consent of the lenders under our Amended and Restated Credit Agreement, holders of Second Lien Notes or holders of Series B Preferred Stock, which may make them more difficult, costly or impractical. Our ability to restructure or refinance our indebtedness will depend on the condition of the capital markets, industry conditions and our financial condition at such time. Current market and worldwide economic conditions are expected to make it more difficult to complete such restructuring or refinancing. Any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. The terms of future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. If we are unable to successfully refinance debt or maintain compliance with the covenants in our debt documents and preferred stock, we may seek an out of court restructuring or, alternatively, protection under Chapter 11 of the U.S. Bankruptcy Code.

Restrictions in our Amended and Restated Credit Agreement, Certificate of Designation for the Series B Preferred Stock and the Note Purchase Agreement limit, and our future debt agreements could limit, our ability to engage in certain activities.

Our Amended and Restated Credit Agreement, Series B Certificate of Designation and the Note Purchase Agreement contain, and our future debt agreements may contain, a number of significant covenants, including restrictive covenants that limit our ability to, among other things:

incur additional indebtedness;

be liable in respect of any third-party guaranty;

incur liens;

make loans to others;

make investments;

pay dividends or make distributions to third parties;

liquidate, merge or consolidate with another entity;

enter into commodity hedges exceeding a specified percentage of our expected production;

enter into interest rate hedges exceeding a specified percentage of our outstanding indebtedness;

sell properties or assets;

issue additional shares of capital stock; and

engage in certain other transactions without the prior consent of the holders of the Second Lien Notes, the Series B Preferred Stock or JPMorgan Chase Bank, N.A. and the lenders under the Amended and Restated Credit Agreement.

In addition, our Amended and Restated Credit Agreement and the Note Purchase Agreement require us to maintain certain financial ratios, which may also limit our ability to engage in certain transactions.


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The restrictions in our Amended and Restated Credit Agreement, Series B Certificate of Designation and the Note Purchase Agreement limit our ability to obtain future financings to withstand the recent downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under our Amended and Restated Credit Agreement, Series B Certificate of Designation and the Note Purchase Agreement impose on us.

If we are unable to comply with restrictions and covenants in our Amended and Restated Credit Agreement or Note Purchase Agreement, there could be a default under the terms of the agreements, which could result in termination of the commitments, foreclosure by our lenders or second lien holders or an acceleration of payments of funds that we have borrowed. The Class A Common Stock may not receive any value in such a scenario.

Although we were in compliance with all of our financial ratios as of December 31, 2019, we could face challenges meeting certain financial covenants under our Amended and Restated Credit Agreement or Note Purchase Agreement in the future. In addition to financial covenants, our Amended and Restated Credit Agreement and the Note Purchase Agreement contain a number of other covenants, and a breach in any of these covenants in the future likely would result in a default after any applicable grace periods. In addition, the covenants in our Amended and Restated Credit Agreement and Note Purchase Agreement are complex and subject to differing interpretations. As a result, disputes over the interpretation of these covenants may arise, particularly during disruptions in market conditions, such as the one we are currently experiencing, and may include claims of a breach in one or more covenants and even claims of a breach, which could have a material adverse effect on our financial condition. If a default has occurred and has not been waived, it could result in termination by the lenders of their commitments under the Amended and Restated Credit Agreement, foreclosure by such lenders or holders of our second lien notes against our assets securing their indebtedness or acceleration of the indebtedness outstanding. The accelerated indebtedness may become immediately due and payable. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such indebtedness. Even if new financing were available at that time, it may not be on terms that are acceptable to us. As a result we may seek to restructure the company or we may be forced into bankruptcy or liquidation. If, during an event of default, our lenders or second lien holders exercise their right to proceed against the collateral and take control of substantially all of our material operating assets, our assets may not be sufficient to repay in full the amounts owed to our lenders, second lien holders or our other debt holders. The Class A Common Stock may not receive any value or payments in a restructuring or similar scenario. Even if the lenders or holders do not foreclose on the collateral, such an event of default could cause a significant decline in the value of the Class A Common Stock.

The Amended and Restated Credit Agreement requires Rosehill Operating to deliver audited financial statements of Rosehill Operating (without a going concern qualification) to the lenders within 90 days after the end of each fiscal year. We can satisfy this requirement by providing audited financial statements of Rosehill Resources within 90 days after the end of each fiscal year. We failed to provide the lenders with such audited financial statements and other required certificates and operating reports within 90 days after December 31, 2019, which constitutes a default under the Amended and Restated Credit Agreement. However, the Amended and Restated Credit Agreement gives us a 30-day cure period before it becomes an event of default that will allow the lenders to redeem a portion or all amounts outstanding.

Any significant reduction in the borrowing base under our Amended and Restated Credit Agreement as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.

Our Amended and Restated Credit Agreement limits the amounts we can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine at certain periods throughout the year. On March 19, 2020, we announced that we drew the remaining available borrowings under our Amended and Restated Credit Agreement and have no additional capacity. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing our loan. If we do not furnish the information required for the redetermination by the specified date, the lender may nonetheless redetermine the borrowing base in their sole discretion until the relevant information is received. The borrowing base is redetermined on April 1 and October 1 of each year.

We expect the borrowing base to be reduced by the lenders, potentially significantly, in connection with this redetermination that was scheduled for April 1, 2020, and we will be required to repay borrowings in excess of the reduced borrowing capacity. Under the Amended and Restated Credit Agreement, we have the option to repay such excess either in full within 30 days after the redetermination or in monthly installments over a six-month period commencing 30 days following the redetermination. Any reductions to our borrowing capacity at future redetermination dates could result in additional deficiencies that would require us to repay any excess as well. We may not have access to the funds necessary to make such repayment, which would constitute an event of default.


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In the future, we may also not be able to access adequate funding under our Amended and Restated Credit Agreement (or a replacement facility) as a result of a decrease in our borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base or we may be forced to seek other financing or restructuring options in the future and, in such a case, we could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to operate our producing properties, recommence or implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness.

We may not be able to refinance or replace our maturing debt on favorable terms, or at all, which will materially adversely affect our financial condition and results of operations. including our inability to continue as a going concern.

As discussed further under “Management’s Discussion and Analysis of Financial Condition and Results of Operations – Capital Requirements and Sources of Liquidity - Going Concern Assessment and Management’s Plan,” which is incorporated into this risk factor, several conditions and events raise substantial doubt about our ability to continue as a going concern within the next year and one day post issuance of these consolidated financial statements included in this Annual Report.

We are currently exploring options to refinance our existing indebtedness, including restructuring our existing capital and bringing on new sources of capital. There is no assurance, however, that such discussions will result in a refinancing on acceptable terms, if at all. Obtaining such financing is more challenging under current market conditions. Alternative sources of capital, if available at all, could involve the issuance of debt or equity on unfavorable terms or that would result in significant dilution. While we review such liquidity-enhancing alternative sources of capital, we intend to continue to manage our expenditures, including through suspension of our drilling program, a reduction in cash general and administrative expenses and the possible sale of additional non-core properties. We may also sell core and non-core assets and further reduce general and administrative expenses in order to pay down outstanding debt. These transactions or actions could have a material adverse effect on our results of operations and financial condition.

We may incur substantial additional debt, which could decrease our ability to maintain operations or service existing debt obligations.

Subject to the restrictions in our Amended and Restated Credit Agreement, Series B Certificate of Designation and the Note Purchase Agreement (as defined below), we may incur substantial additional debt in the future. We may also consider investments in joint ventures or acquisitions that may increase our indebtedness. Adding debt to existing debt levels could intensify the risks that we face.

Increases in interest rates could adversely affect our business.

Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. Our Amended and Restated Credit Agreement is subject to similar or greater interest rate expenses. While we do have certain swaps in place to protect against future increases in interest rates, these swaps do not protect against all possible future increases in interest rates. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve planned growth and operating results.

Uncertainty about the future of the London Interbank Offer Rate (“LIBOR”) may adversely affect our business and financial results.
 
LIBOR meaningfully influences market interest rates around the globe. In July 2017, the Chief Executive of the United Kingdom Financial Conduct Authority, which regulates LIBOR, announced its intent to stop persuading or compelling banks to submit rates for the calculation of LIBOR to the administrator of LIBOR after 2021. This announcement indicates that the continuation of LIBOR as currently constructed is not guaranteed after 2021. It is impossible to predict whether and to what extent banks will continue to provide LIBOR submissions to the administrator of LIBOR, whether any additional reforms to LIBOR may be enacted in the United Kingdom or elsewhere, and whether other rate or rates may become accepted alternatives to LIBOR.
 

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In 2014, the Federal Reserve Board and the Federal Reserve Bank of New York convened the Alternative Reference Rates Committee (“ARRC”) to identify best practices for alternative reference rates, identify best practices for contract robustness, develop an adoption plan, and create an implementation plan with metrics of success and a timeline. The ARRC accomplished its first set of objectives and has identified the Secured Overnight Financing Rate (“SOFR”) as the rate that represents best practice for use in certain new U.S. dollar derivatives and other financial contracts. The ARRC also published its Paced Transition Plan, with specific steps and timelines designed to encourage adoption of the SOFR. The ARRC was reconstituted in 2018 to help to ensure the successful implementation of the Paced Transition Plan and serve as a forum to coordinate and track planning across cash and derivatives products and market participants currently using LIBOR.

No assurance can be provided that the uncertainties around LIBOR or their resolution will not adversely affect the use, level and volatility of LIBOR or other interest rates or the value of LIBOR-based securities or other securities or financial arrangements. Further, the viability of SOFR as an alternative reference rate and the availability and acceptance of other alternative reference rates are unclear and also may have adverse effects on market rates of interest and the value of securities and other financial arrangements. These uncertainties, proposals and actions to resolve them, and their ultimate resolution also could negatively impact our funding costs, loan and other asset values, asset-liability management strategies, and other aspects of our business and financial results. We will monitor the continuous emergence of SOFR, as it could adversely impact our interest rate risk, and therefore the amount of interest we pay on liabilities currently measured at LIBOR.

A fundamental change under our Series A Preferred Stock, a change of control under our Series B Preferred Stock or an event of default under our Amended and Restated Credit Agreement or our Note Purchase Agreement would all have a material adverse effect on our financial condition and results of operations.
Although we were not in default under our Series A Preferred Stock, our Series B Preferred Stock, our Amended and Restated Credit Agreement or our Note Purchase Agreement as of December 31, 2019, we cannot provide assurance that factors such as the current market conditions will not cause a fundamental change, change of control, or event of default to occur. A default under our Amended and Restated Credit Agreement or Note Purchase Agreement could result in termination by the lenders of their commitments under the Amended and Restated Credit Agreement, foreclosure by such lenders or holders of our second lien notes against our assets securing their indebtedness or acceleration of the indebtedness outstanding. Additionally, a fundamental change under our Series A Preferred Stock or a change of control under our Series B Preferred Stock would result in the holder’s right to convert or the Company’s obligation to redeem such stock, respectively.
Examples of an event of default under one or more of these instruments and agreements include if our Class A Common Stock were to be delisted from Nasdaq, if our revolving credit exposures under our Amended and Restated Credit Agreement were to exceed the borrowing base then in effect, if we redeem equity (including preferred stock following a default) without consent of our lenders, or if we were to breach the financial covenants in our Amended and Restated Credit Agreement or our Note Purchase Agreement. An event of default under our Amended and Restated Credit Agreement causes a cross-default under our Note Purchase Agreement. With respect to the risk of our Class A Common Stock being delisted from Nasdaq, please read “The market price of the Class A Common Stock may continue to decline and we may not be able to maintain listing on Nasdaq.” A delisting of our Class A Common Stock would trigger an event of default under our Amended and Restated Credit Agreement and potential redemption of our Series B Preferred Stock. Any such event of default, and any subsequent actions taken by our lenders or second lien note holders would have a material adverse effect on our financial condition and results of operations and would contribute to the loss of all or part of the value of our Class A Common Stock.
Risks Related to the Class A Common Stock and Our Capital Structure

We are a holding company. Our sole material asset is our equity interest in Rosehill Operating and we are accordingly dependent upon distributions from Rosehill Operating to pay taxes, make payments under the Tax Receivable Agreement, cover our corporate and other overhead expenses and make payments with respect to our Series A Preferred Stock and Series B Preferred Stock.

We are a holding company and have no material assets other than our equity interest in Rosehill Operating. We have no independent means of generating revenue. To the extent Rosehill Operating has available cash, we intend to cause Rosehill Operating to make (i) generally pro rata distributions to its unitholders, including us, in an amount at least sufficient to allow us to pay dividends with respect to the Series A Preferred Stock and the Series B Preferred Stock, pay our taxes and to make payments under the Tax Receivable Agreement with Tema and (ii) non-pro rata payments to us to reimburse us for our corporate and other overhead expenses. To the extent that we need funds and Rosehill Operating or its subsidiaries are restricted from making such distributions or payments under applicable law or regulation or under the terms of any financing arrangements, or are otherwise unable to provide such funds, our liquidity and financial condition could be materially adversely affected.

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The market price of the Class A Common Stock may continue to decline and we may not be able to maintain listing on Nasdaq. A delisting of our Class A Common Stock would trigger an event of default under our Amended and Restated Credit Agreement
and potential redemption of our Series B Preferred Stock.

Fluctuations in the price of the Class A Common Stock could contribute to the loss of all or part of your investment. The trading price of the Class A Common Stock could be volatile and subject to wide fluctuations in response to various factors, some of which are beyond our control. Any of these factors could have a material adverse effect on your investment and the Class A Common Stock may trade at prices significantly below the price you paid for them. In such circumstances, the trading price of the Class A Common Stock may not recover and may experience a further decline.

In addition, broad market and industry factors may materially harm the market price of the Class A Common Stock irrespective of our operating performance. The stock market in general and Nasdaq have experienced price and volume fluctuations that have often been unrelated or disproportionate to the operating performance of the particular companies affected. The trading prices and valuations of our Class A Common Stock and Public Warrants, which trade on The Nasdaq Capital Market, may not be predictable. The recent historic decline in the stock market or a loss of investor confidence in the market for retail stocks or the stocks of other companies which investors perceive to be similar to us could continue to depress the price of the Class A Common Stock regardless of our business, prospects, financial conditions or results of operations. A decline in the market price of the Class A Common Stock also could adversely affect our ability to issue additional securities and our ability to obtain additional financing in the future.

As of March 27, 2020, the closing price of our stock was $0.29 per share. On March 23, 2020, we received a letter from The Nasdaq Stock Market LLC (“Nasdaq”) indicating that for the 30 consecutive business days ending March 20, 2020, the bid price for the Company’s common stock had closed below the $1.00 per share minimum bid price requirement for continued listing on The Nasdaq Capital Market under Nasdaq Listing Rule 5550(a)(2). We cannot guarantee that we will be able to maintain listing of our Class A Common Stock, Class A Common Stock Public Units, or Public Warrants on The Nasdaq Capital Market. Any delisting would contribute to the loss of all or part of the value of our Class A Common Stock and could give holders of our Series B Preferred Stock the right to seek redemption of the Series B Preferred Stock for cash. A delisting would also trigger an Event of Default under our Amended and Restated Credit Agreement and Second Lien Notes.

If securities or industry analysts do not publish or cease publishing research or reports about us, our business, or our market, or if they change their recommendations regarding the Class A Common Stock adversely, the price and trading volume of the Class A Common Stock could decline.

The trading market for the Class A Common Stock relies in part on the research and reports that industry or financial analysts publish about us or our business. We do not control these analysts and there can be no assurance that any will cover us in the future. Furthermore, if one or more analysts do cover us and downgrade or provide negative outlook on our stock or our industry, or the stock of any of our competitors, or publishes inaccurate or unfavorable research about our business, the price of the Class A Common Stock could decline. If one or more of these analysts commence and subsequently cease coverage of our business or fail to publish reports on us regularly, we could lose visibility in the market, which in turn could cause our stock price or trading volume to decline.

Tema and KLR Energy Sponsor, LLC (“KLR Sponsor”) own a significant percentage of our outstanding voting common stock.

Tema and KLR Sponsor currently beneficially own approximately 70.4% of our voting common stock and, upon the full conversion of our Series A Preferred Stock, will beneficially own approximately 61.8% of our voting common stock. As long as Tema and KLR Sponsor own or control a significant percentage of outstanding voting power, they will continue to have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our charter or bylaws, or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.

The interests of Tema and KLR Sponsor may not align with the interests of our other stockholders. Tema and KLR Sponsor may acquire and hold interests in businesses that compete directly or indirectly with us. Tema and KLR Sponsor may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our second amended and restated certificate of incorporation (the “certificate of incorporation”), amended and restated bylaws and the Shareholders’ and Registration Rights Agreement, dated as of December 20, 2016, by and among the Company, Tema, KLR Sponsor, Anchorage Illiquid Opportunities V, L.P. and AIO V AIV 3 Holdings, L.P. (the “SHRRA”), provide that, subject to certain limitations, we renounce any interest or expectancy in the business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.

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We are currently a “controlled company” within the meaning of the Nasdaq listing rules, and we may continue to rely on exemptions from certain corporate governance requirements that provide protection to stockholders of other companies.

Because Tema and KLR Sponsor control a majority of the combined voting power of all classes of our outstanding voting stock, we are a “controlled company” under Nasdaq corporate governance listing standards. Under the Nasdaq rules, a company of which more than 50% of the voting power is held by another person or group of persons acting together is a controlled company and may elect not to comply with certain Nasdaq corporate governance requirements, including the requirements that:

a majority of the board of directors consist of independent directors;

the nominating and governance committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities; and

the compensation committee be composed entirely of independent directors with a written charter addressing the committee’s purpose and responsibilities.

In the event that we conduct equity offerings in the future, Tema and KLR Sponsor may cease to control a majority of the combined voting power of all classes of our outstanding voting stock. Accordingly, we may no longer be a “controlled company” within the meaning of the rules of Nasdaq. Under Nasdaq rules, a company that ceases to be a controlled company must comply with the independent board committee requirements as they relate to the nominating and corporate governance and compensation committees on the following phase-in schedule: (1) one independent committee member at the time it ceases to be a controlled company, (2) a majority of independent committee members within 90 days of the date it ceases to be a controlled company and (3) all independent committee members within one year of the date it ceases to be a controlled company. Additionally, Nasdaq rules provide a 12-month phase-in period from the date a company ceases to be a controlled company to comply with the majority independent board requirement. During these phase-in periods, our stockholders will not have the same protections afforded to stockholders of companies of which the majority of directors are independent. Additionally, if, within the phase-in periods, we are not able to recruit additional directors who would qualify as independent, or otherwise comply with Nasdaq rules, we may be subject to enforcement actions by Nasdaq. Furthermore, a change in our board of directors and committee membership may result in a change in corporate strategy and operation philosophies, and may result in deviations from our current growth strategy.

Future sales of our common stock could reduce our stock price, and any additional capital raised by us through the sale of equity or convertible securities may dilute your ownership in us.

We may sell additional shares of Class A Common Stock or securities convertible into Class A Common Stock in subsequent public or private offerings.

Downward pressure on the market price of our Class A Common Stock that likely will result from sales of our Class A Common Stock issued in connection with the exercise of the warrants for shares of Class A Common Stock or the conversion of the Class B Common Stock or Series A Preferred Stock could encourage short sales of our Class A Common Stock by market participants. Generally, short selling means selling a security, contract or commodity not owned by the seller. The seller is committed to eventually purchase the financial instrument previously sold. Short sales are used to capitalize on an expected decline in the security’s price. Such sales of our Class A Common Stock could have a tendency to depress the price of the stock, which could increase the potential for short sales.
 

We cannot predict the size of future issuances of our Class A Common Stock or securities convertible into Class A Common Stock or the effect, if any, that future issuances and sales of shares of our Class A Common Stock will have on the market price of our Class A Common Stock. Sales of substantial amounts of our Class A Common Stock (including shares issued in connection with an acquisition), or the perception that such sales could occur, may adversely affect prevailing market prices of our common stock.

Shares of the Class A Common Stock are equity interests and are therefore subordinated to our indebtedness and preferred stock.

In the event of our liquidation, dissolution or winding up, the Class A Common Stock would rank below our Series A Preferred Stock and Series B Preferred Stock and all secured debt claims against us. As a result, holders of the Class A Common Stock will not be entitled to receive any payment or other distribution of assets upon our liquidation, dissolution or winding up until all of our obligations to our secured debt holders and to holders of our Series A Preferred Stock and Series B Preferred Stock have been satisfied.                             

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Because we currently have no plans to pay cash dividends on our Class A Common Stock, you may not receive any return on investment unless you sell your Class A Common Stock for a price greater than that which you paid for it.

We currently do not expect to pay any cash dividends on our Class A Common Stock. Any future determination to pay cash dividends or other distributions on our Class A Common Stock will be at the discretion of the board of directors and will be dependent on our earnings, financial condition, results of operations, capital requirements and contractual, regulatory and other restrictions, including restrictions contained in the senior secured credit facility or agreements governing any existing and future outstanding indebtedness we or our subsidiaries may incur, on the payment of dividends by us or by our subsidiaries to us, and other factors that our board of directors deems relevant.

As a result, you may not receive any return on an investment in our Class A Common Stock unless you sell shares of Class A Common Stock for a price greater than that which you paid for it.
 

Holders of our Series B Preferred Stock have certain limited consent rights that could prevent us from taking certain corporate actions, and as a result may adversely affect our business, operating results and stock price.

Holders of our Series B Preferred Stock have certain limited consent rights with respect to our ability to take certain corporate actions, including the following:

the issuance, authorization or creation of any class or series of stock senior to or on par with the Series B Preferred Stock;

the incurrence of additional indebtedness, provided that such indebtedness may be incurred if, after giving pro forma effect to the incurrence and any application of the proceeds thereof, we maintain a Leverage Ratio (as defined in the Series A Certificate of Designation) of less than 4.00 to 1.00;

the issuance or incurrence of high-yield debt, unless the debt (A) does not have an all-in interest rate together with any component of yield greater than the Second Lien Notes (as defined below) and a make-whole provision less favorable than the Second Lien Notes and (B) is used to refinance the Second Lien Notes;

the entry into any joint venture agreement or issuance of equity securities of our subsidiaries, other than to us or our wholly-owned subsidiaries;

sales of certain property having a fair market value greater than $15.0 million in any fiscal year and $40.0 million in the aggregate;

and certain property acquisitions or investments in excess of $15.0 million in any fiscal year and $40.0 million in the aggregate, unless such acquisitions or investments are financed solely using our common equity (or cash proceeds of the issuance of our common equity).

The consent rights of the holders of our Series B Preferred Stock could prevent us from obtaining future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities, and as a result may adversely affect our business, operating results and stock price.

Anti-takeover provisions contained in our certificate of incorporation and bylaws, as well as provisions of Delaware law, could impair a takeover attempt.

Our certificate of incorporation and bylaws contain provisions that may discourage unsolicited takeover proposals that stockholders may consider to be in their best interests. We are also subject to anti-takeover provisions under Delaware law, which could delay or prevent a change of control. Together these provisions may make more difficult the removal of management and may discourage transactions that otherwise could involve payment of a premium over prevailing market prices for our securities. These provisions include:

a staggered board providing for three classes of directors, which limits the ability of a stockholder or group to gain control of our board;

no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;


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the right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director in certain circumstances, which prevents stockholders from being able to fill vacancies on our board of directors;

the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;

the ability of each of Tema or KLR Sponsor to call a special meeting of stockholders, provided that such person owns 15% or more of the outstanding shares of common stock until the Trigger Date, as defined in our certificate of incoporation, and thereafter prohibit such ability;

a prohibition on stockholders calling a special meeting upon and following the Trigger Date, which forces stockholder action to be taken at an annual or special meeting of our stockholders called by the board;

the requirement that a meeting of stockholders may be called only by the board of directors after the Trigger Date, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;

providing that after the Trigger Date, directors may be removed prior to the expiration of their terms by stockholders only for cause or upon the affirmative vote of 75% of the voting power of all outstanding shares of the combined company;

a requirement that changes or amends the certificate of incorporation or the bylaws must be approved (i) before the Trigger Date, by a majority of the voting power of outstanding common stock of the combined company, which such majority shall include at least 80% of the shares then held by KLR Sponsor and Tema, and (ii) thereafter, certain changes or amendments must be approved by at least 75% of the voting power of outstanding common stock of the combined company; and

advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.

Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.

We are subject to laws, regulations and rules enacted by national, regional and local governments and Nasdaq. In particular, we are required to comply with certain SEC, Nasdaq and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations.

We may be required to make payments under the Tax Receivable Agreement for certain tax benefits that we may claim, and the amounts of such payments could be significant.

In connection with the closing of the Transaction, we entered into the Tax Receivable Agreement with Tema. This agreement generally provides for the payment by us to Tema of 90% of the net cash savings, if any, in U.S. federal, state and local income tax and franchise tax that we actually realize (computed using simplifying assumptions to address the impact of state and local taxes) or are deemed to realize in certain circumstances in periods after the Transaction as a result of certain increases in the tax basis in the assets of Rosehill Operating and certain benefits attributable to imputed interest. We will retain the benefit of the remaining 10% of these cash savings.

The term of the Tax Receivable Agreement will continue until all tax benefits that are subject to the Tax Receivable Agreement have been utilized or expired, unless we exercise our right to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control (or the Tax Receivable Agreement is terminated early due to our breach of a material obligation thereunder), and we make the termination payment specified in the Tax Receivable Agreement. In addition, payments we make under the Tax Receivable Agreement will be increased by any interest accrued from the due date (without extensions) of the corresponding tax return.


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The payment obligations under the Tax Receivable Agreement are our obligations and not obligations of Rosehill Operating, and the payments required under the Tax Receivable Agreement may be substantial. Estimating the amount and timing of payments that may become due under the Tax Receivable Agreement is by its nature imprecise. For purposes of the Tax Receivable Agreement, cash savings in tax generally are calculated by comparing our actual tax liability (determined by using the actual applicable U.S. federal income tax rate and an assumed combined state and local income tax rate) to the amount we would have been required to pay had we not been able to utilize any of the tax benefits subject to the Tax Receivable Agreement. The actual increase in tax basis, as well as the amount and timing of any payments under the Tax Receivable Agreement, are dependent upon significant future events and assumptions, including the timing of the redemptions of Rosehill Operating Common Units, the price of our Class A Common Stock at the time of each redemption, the extent to which such redemptions are taxable transactions, the amount of Tema’s tax basis in its Rosehill Operating Common Units at the time of the relevant redemption, the depreciation and amortization periods that apply to the increase in tax basis, the amount and timing of taxable income we generate in the future, the U.S. federal income tax rates then applicable, and the portion of our payments under the Tax Receivable Agreement that constitute imputed interest or give rise to depreciable or amortizable tax basis. The payments under the Tax Receivable Agreement will not be conditioned upon a holder of rights under the Tax Receivable Agreement having a continued ownership interest in us or Rosehill Operating.

In certain cases, payments under the Tax Receivable Agreement may be accelerated or significantly exceed the actual benefits, if any, we realize in respect of the tax attributes subject to the Tax Receivable Agreement.

If we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control or it is terminated early due to our breach of a material obligation thereunder, our obligations under the Tax Receivable Agreement would accelerate and would require us to make a substantial immediate lump-sum payment. This payment would equal the present value of the hypothetical future payments that could be required to be paid under the Tax Receivable Agreement (determined by applying a discount rate equal to the one-year London Interbank Offered Rate (“LIBOR”) plus 150 basis points). The calculation of hypothetical future payments will be based upon certain assumptions and deemed events set forth in the Tax Receivable Agreement, including (i) the assumption that we have sufficient taxable income to fully utilize the tax benefits covered by the Tax Receivable Agreement and (ii) the assumption that any Rosehill Operating Common Units (other than those held by us) outstanding on the termination date are deemed to be exchanged on the termination date. Any early termination payment may be made significantly in advance of the actual realization, if any, of the future tax benefits to which the termination payment relates.

Upon an early termination of the Tax Receivable Agreement, we could be required to make payments under the Tax Receivable Agreement that exceed our actual cash tax savings, if any, in respect of the tax attributes subject to the Tax Receivable Agreement. In these situations, our obligations under the Tax Receivable Agreement could have a substantial negative impact on our liquidity and could have the effect of delaying, deferring or preventing certain mergers, asset sales, or other forms of business combinations or changes of control. For example, if the Tax Receivable Agreement had been terminated at December 31, 2019, the estimated termination payments would, in the aggregate, have been approximately $42.5 million (calculated using a discount rate equal to one-year LIBOR plus 150 basis points, applied against an undiscounted liability of $56.5 million). The foregoing number is merely an estimate and the actual payments could differ materially. There can be no assurance that we will be able to finance our obligations under the Tax Receivable Agreement.

In the event that we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control, the consideration payable to holders of our Class A Common Stock could be substantially reduced.

If we elect to terminate the Tax Receivable Agreement early within thirty (30) days of certain mergers or other changes of control, we would be obligated to make a substantial, immediate lump-sum payment, and such payment may be significantly in advance of, and may materially exceed, the actual realization, if any, of the future tax benefits to which the payment relates. As a result of this payment obligation, holders of our Class A Common Stock could receive substantially less consideration in connection with a change of control transaction than they would receive in the absence of such obligation. Further, our payment obligations under the Tax Receivable Agreement will not be conditioned upon Tema having a continued interest in us or Rosehill Operating. Accordingly, Tema’s interests may conflict with those of the holders of our Class A Common Stock. Please read “In certain cases, payments under the Tax Receivable Agreement may be accelerated or significantly exceed the actual benefits, if any, we realize, in respect of the tax attributes subject to the Tax Receivable Agreement” and “Certain Relationships and Related Party Transactions - Agreements Relating to the Transaction - Tax Receivable Agreement.”

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We will not be reimbursed for any payments made under the Tax Receivable Agreement in the event that any tax benefits are subsequently disallowed.

Payments under the Tax Receivable Agreement will be based on the tax reporting positions that we will determine. Tema will not reimburse us for any payments previously made under the Tax Receivable Agreement if any tax benefits that have given rise to payments under the Tax Receivable Agreement are subsequently disallowed, except that excess payments made to Tema will be netted against payments that would otherwise be made to Tema, if any, after our determination of such excess. As a result, in such circumstances, we could make payments that are greater than our actual cash tax savings, if any, and may not be able to recoup those payments, which could adversely affect our liquidity.

In certain circumstances, Rosehill Operating will be required to make tax distributions and tax advances to its unitholders, and the tax distributions and tax advances that Rosehill Operating will be required to make may be substantial.

Pursuant to the Second Amended LLC Agreement, Rosehill Operating will make generally pro rata cash distributions, or tax distributions, to its unitholders, including us, in an amount sufficient to allow us to pay our taxes and to allow us to make payments under the Tax Receivable Agreement with Tema. In addition to these pro rata distributions, certain Rosehill Operating unitholders will be entitled to receive tax advances in an amount sufficient to allow each such unitholder to pay its respective taxes on such holder’s allocable share of Rosehill Operating’s taxable income. Any such tax advance will be calculated after taking into account certain other distributions or payments received by the unitholders from Rosehill Operating. Under the applicable tax rules, Rosehill Operating is required to allocate net taxable income disproportionately to its members in certain circumstances. Tax advances will be determined based on an assumed individual tax rate and will be repaid upon exercise of Tema’s redemption right or the call right, as applicable.

Funds used by Rosehill Operating to satisfy its tax distribution and tax advance obligations will not be available for reinvestment in our business. Moreover, the tax distributions and tax advances Rosehill Operating will be required to make may be substantial, and because of the disproportionate allocation of net taxable income, may exceed the actual tax liability for some of the existing owners of Rosehill Operating.

We qualify as an emerging growth company and a smaller reporting company, and as a result, we will not be required to comply with certain disclosure requirements that apply to other public companies.

We qualify as an “emerging growth company” as defined in the JOBS Act. As such, we take advantage of certain exemptions from various reporting requirements applicable to other public companies that are not emerging growth companies for as long as we continue to be an emerging growth company, including (i) the exemption from the auditor attestation requirements with respect to internal control over financial reporting under Section 404 of the Sarbanes-Oxley Act, (ii) the exemptions from say-on-pay, say-on-frequency and say-on-golden parachute voting requirements and (iii) reduced disclosure obligations regarding executive compensation in our periodic reports and proxy statements.

Notwithstanding the above, we are also 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 public float of less than $250 million. As a “smaller reporting company,” we may provide simplified executive compensation disclosures and have certain other scaled disclosure obligations in our SEC filings, including, among other things, being required to provide only two years of audited financial statements in annual reports. This may make it more difficult for investors and analysts to conduct a full comparison of our disclosure and our peers’ disclosures, and the market might impose a discount as a result.

ITEM 1B. UNRESOLVED STAFF COMMENTS

None.


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ITEM 2. PROPERTIES

Our properties

Our properties are located within the Northern and Southern Delaware Basins, sub-basins of the Permian Basin.  The Permian Basin consists of mature, legacy onshore oil and liquids-rich natural gas reservoirs that span approximately 86,000 square miles in West Texas and New Mexico. The Permian Basin is composed of five sub regions: the Delaware Basin, the Central Basin Platform, the Midland Basin, the Northwest Shelf and the Eastern Shelf. The Permian Basin is an attractive operating area due to its multiple horizontal and vertical target formations, favorable operating environment, high oil and liquids-rich natural gas content, mature infrastructure, well-developed network of oilfield service providers, long-lived reserves with consistent reservoir quality and historically high drilling success rates.

Oil and Natural Gas Reserves

Estimation and review of proved reserves

Proved reserve estimates as of December 31, 2019 were prepared by Netherland, Sewell & Associates, Inc. (“NSAI”), our independent petroleum engineers. NSAI does not own an interest in any of our properties, nor are they employed by us on a contingent basis. A copy of our independent petroleum engineer’s proved reserve report as of December 31, 2019 is attached as an exhibit to this Annual Report on Form 10-K.

NSAI is a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserves report  incorporated herein are Neil H. Little and Mike K. Norton. Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing consulting petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from the University of Houston in 2007 with a Master of Business Administration Degree. Mr. Norton, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 441), has been practicing consulting petroleum geoscience at NSAI since 1989 and has over 10 years of prior industry experience. He graduated from Texas A&M University in 1978 with a Bachelor of Science Degree in Geology.

These technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

Our internal staff of petroleum engineers and geoscience professionals worked closely with our independent petroleum engineers to ensure the integrity, accuracy and timeliness of the data used to calculate the proved reserves relating to our assets. Our internal technical team members met with our independent petroleum engineers periodically to discuss the assumptions and methods used in the proved reserve estimation process. We provided historical information to our independent petroleum engineers for our properties, such as ownership interest, oil and natural gas production, well test data, commodity prices, subsurface geologic data and operating and development costs. Our Vice President of Commercial and Reserves is primarily responsible for overseeing the preparations of our reserve estimates. Our Vice President of Commercial and Reserves holds a bachelor’s degree in Mechanical Engineering from Simon Bolivar University (Venezuela) and a Masters of Business Administration from IE Business School and has nearly 20 years of experience across multiple facets of the energy industry and brings a wealth of experience in portfolio management, acquisition and divestitures, capital allocation and asset development/optimization. Our Reservoir Engineer and Reserves Manager holds a Bachelor of Science in Petroleum Engineering from Texas A&M University and has over 15 years of industry experience and has worked at several known companies across multiple basins in the United States. On March 27, 2020, we announced that we eliminated 52 full-time employee positions, which included all of our petroleum engineering and geoscience professionals, including our Reservoir Engineer and Reserves Manager.

The preparation of our proved reserve estimates as of December 31, 2019 was completed in accordance with our internal control procedures. These procedures, which are intended to ensure reliability of reserve estimations, include the following:
 
review and verification of producing formations, well targets and the development plan by our Vice President of Commercial and Reserves and Reservoir Engineer and Reserves Manager;

review and verification of historical production data, which data is based on actual production as reported by us;

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review of well by well reserve estimates by independent reserve engineers;

review by our Vice President of Commercial and Reserves and Reservoir Engineer and Reserves Manager of all of our reported proved reserves, including the review of all significant reserve changes and all new PUD additions;

direct reporting responsibilities by our Vice President of Commercial and Reserves to our Chief Executive Officer; and

verification of property ownership interests by our land department.

Under the rules promulgated by the SEC, proved reserves are those quantities of oil and natural 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). If deterministic methods are used, the SEC has defined reasonable certainty for proved reserves as a “high degree of confidence that the quantities will be recovered.” All of our proved reserves were estimated using a deterministic method. The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and natural gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions established under SEC rules. The process of estimating the quantities of recoverable oil and natural gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into four broad categories or methods: (i) production performance-based methods; (ii) material balance-based methods; (iii) volumetric-based methods; and (iv) analogy. These methods may be used singularly or in combination by the reserve evaluator in the process of estimating the quantities of reserves. Reserves for proved developed producing wells were estimated using production performance methods for the vast majority of properties. Certain new producing properties with very little production history were forecast using a combination of production performance and analogy to similar production, both of which are considered to provide a reasonably high degree of accuracy. Non-producing reserve estimates for developed and undeveloped properties were forecasted using analogy methods. This method provides a reasonably high degree of accuracy for predicting proved developed non-producing and PUD locations for our properties, due to the abundance of analog data.

Summary of oil, natural gas and NGL reserves
 
At December 31, 2019, our estimated proved oil and natural gas reserves were 62,763 MBoe and determined in accordance with the rules and regulations of the SEC. Based on this report, at December 31, 2019, our proved reserves were approximately 65% oil, 17% natural gas, 18% NGLs and 58% proved developed. The calculated percentages include proved developed non-producing reserves. At December 31, 2019, all of our proved reserves were located in the Permian Basin.

Estimated proved reserves were determined using average first-day-of-the-month prices for the prior twelve months in accordance with SEC guidance. For oil volumes, the average West Texas Intermediate posted price was adjusted for quality, transportation fees and a regional price differential. For natural gas volumes, the average Henry Hub spot price was adjusted for energy content and a regional price differential. For NGL volumes, NGL prices range from 25% to 37%, depending on the property, of the average West Texas Intermediate posted price, except December 31, 2017 estimated proved NGL reserves used the average Mont Belvieu posted price, as adjusted. All prices are held constant throughout the producing life of the properties.

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The following table presents our estimated net proved oil, natural gas and NGLs reserves as of the fiscal years indicated:
 
 
December 31,
 
 
2019
 
2018
 
2017
Proved reserves:
 
 
 
 
 
 
Oil (MBbls)
 
40,716

 
33,158

 
18,436

Natural gas (MMcf)
 
64,160

 
44,583

 
39,316

NGLs (MBbls)
 
11,354

 
7,775

 
6,142

        Total (MBoe)
 
62,763

 
48,364

 
31,131

Proved developed reserves:
 
 
 
 
 
 
Oil (MBbls)
 
23,967

 
18,464

 
8,814

Natural gas (MMcf)
 
36,643

 
26,194

 
14,171

NGLs (MBbls)
 
6,301

 
4,477

 
2,285

        Total (MBoe)
 
36,375

 
27,307

 
13,461

Proved undeveloped reserves:
 
 
 
 
 
 
Oil (MBbls)
 
16,749

 
14,694

 
9,622

Natural gas (MMcf)
 
27,517

 
18,388

 
25,145

NGLs (MBbls)
 
5,053

 
3,298

 
3,857

        Total (MBoe)
 
26,388

 
21,057

 
17,670

 
 
 
 
 
 
 
Oil (per Bbl)
 
$
55.85

 
$
65.56

 
$
51.34

Natural gas (per Mcf)
 
$
2.58

 
$
3.10

 
$
2.98

NGLs (per Bbl)
 
$
15.75

 
$
23.02

 
$
31.82


Reserve engineering is and must be recognized as a subjective process of estimating volumes of economically recoverable oil and natural gas that cannot be measured in an exact manner. The accuracy of any reserve estimate is a function of the quality of available data and of engineering and geological interpretation. As a result, the estimates of different engineers often vary. In addition, the results of drilling, testing and production may justify revisions of such estimates. Accordingly, reserve estimates often differ from the quantities of oil, natural gas and NGLs that are ultimately recovered. Estimates of economically recoverable oil, natural gas and NGLs and of future net revenues are based on a number of variables and assumptions, all of which may vary from actual results, including geologic interpretation, prices and future production rates and costs. Please read “Risk Factors.”

Our proved reserves increased by 14,399 MBoe from 48,364 MBoe at December 31, 2018 to 62,763 MBoe at December 31, 2019. The increase was primarily due to extensions of 19,587 MBoe and net positive revisions of 3,372 MBoe partially offset by production of 7,587 MBoe. Additional information regarding our proved reserves can be found in the notes to our consolidated financial statements included elsewhere in this Annual Report on Form 10-K and the reserve report as of December 31, 2019, which is included as an exhibit to this Annual Report on Form 10-K.


50



PUDs

PUDs will be converted from undeveloped to developed as the applicable wells are drilled and begin production. The following table summarizes the changes in PUD reserves that occurred during 2019:
 
2019
 
(MBoe)
PUDs at December 31, 2018
21,057

Extensions, discoveries and other additions
13,718

Performance and price revisions
408

Acquisition of reserves

Disposition of reserves
(705
)
Transferred to proved developed reserves
(8,090
)
PUDs at December 31, 2019
26,388


As of December 31, 2019, we had 48 operated PUD locations booked of which, 2 locations were originally booked at December 31, 2015, 1 locations was originally booked at December 31, 2016, 2 locations were originally booked at December 31, 2017, 19 locations were booked at December 31, 2018 and 24 locations were booked at December 31, 2019. During 2019, we spent a total of $93.3 million related to the development of PUDs, which resulted in the conversion of 8.1 MMBoe of PUDs to proved developed reserves. Our development plan resulted in 17 PUDs drilled in 2019. As of December 31, 2019, we had 5 DUCs included in PUDs which we incurred approximately $10.6 million developing. On March 19, 2020, we announced that we halted future drilling and completions activity for 2020 and had drilled 8 wells and completed 8 wells to date in 2020. We expect to be required to reclassify some portion of our PUDs because such a deferral of planned capital expenditures means we will be unable to develop such reserves within five years of their initial booking.

Oil, Natural Gas and NGLs Production Prices and Production Costs

The prices that we receive for the oil, natural gas and NGLs we produce is largely a function of market supply and demand. Demand is impacted by general economic conditions, weather and other seasonal conditions, including hurricanes and tropical storms. Over or under supply of oil or natural gas can result in substantial price volatility. Historically, commodity prices have been volatile, and we expect that volatility to continue in the future. A substantial or extended decline in oil, natural gas and NGLs prices or poor drilling results could have a material adverse effect on our financial position, results of operations, cash flows, quantities of oil, natural gas and NGL reserves that may be economically produced and our ability to access capital markets. Please see “Risk Factors - Risks Related to Our Operations - Oil, natural gas and NGL prices are volatile. A reduction or sustained decline in oil, natural gas and NGL prices could adversely affect our business, financial condition and results of operations and our ability to meet our capital expenditure obligations and financial commitments.”


51



The following table sets forth information regarding our net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
 
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
Production data:
 
 
 
 
 
 
  Oil (MBbls)
 
5,411

 
4,913

 
1,271

  Natural gas (MMcf)
 
6,352

 
5,231

 
2,709

  NGLs (MBbls)
 
1,117

 
908

 
408

    Total production (MBoe)
 
7,587

 
6,693

 
2,131

    Average daily production (Boe/d)
 
20,786

 
18,337

 
5,838

Average realized prices before effect of derivatives (1):
 
 
 
 
 
 
  Oil (per Bbl)
 
$
52.99

 
$
55.27

 
$
48.46

  Natural gas (per Mcf)
 
0.39

 
1.80

 
2.65

  NGLs (per Bbl)
 
11.71

 
23.07

 
18.31

    Average price (per Boe)
 
$
39.84

 
$
45.10

 
$
35.77

Average price after the effect of settled derivatives (per Boe) (1)
 
$
37.91

 
$
42.79

 
$
35.85

Average costs (per Boe)
 
 
 
 
 
 
Lease operating expenses
 
$
4.92

 
$
5.66

 
$
4.86

Production and ad valorem taxes
 
2.30

 
2.34

 
1.91

Gathering and transportation
 
0.76

 
0.74

 
1.40

Depreciation, depletion, amortization and accretion
 
18.18

 
21.19

 
16.94

Impairment of oil and natural gas properties
 

 

 
0.50

Exploration costs
 
2.10

 
0.65

 
0.82

General and administrative, excluding stock-based compensation
 
3.88

 
3.58

 
5.72

Stock-based compensation
 
0.83

 
0.97

 
0.58

Transaction costs
 

 

 
1.23

(Gain) loss on disposition of property and equipment
 
(1.47
)
 
0.07

 
(2.34
)
Total operating expenses per Boe
 
$
31.50

 
$
35.20

 
$
31.62


(1)
Average prices shown in the table reflect prices both before and after the effects of commodity hedging settlements. Our calculation of such effects includes both gains and losses on cash settlements for commodity derivative transactions and premiums paid or received on options that settled during the period.


52



Drilling activity and results

The following table summarizes our drilling activity for the last three years.
 
 
Year Ended December 31,
 
Year Ended December 31,
 
 
2019
 
2018
 
2017
 
2019
 
2018
 
2017
 
 
Gross
 
Net
Exploratory Wells:
 
 
 
 
 
 
 
 
 
 
 
 
Productive (1)
 
11

 
17

 
15

 
11

 
17

 
15

Dry
 

 

 

 

 

 

Development Wells: 
 
 
 
 
 
 
 
 
 
 
 
 
Productive (1)
 
19

 
13

 
4

 
19

 
13

 
4

Dry
 

 

 

 

 

 

Total Wells:
 
 
 
 
 
 
 
 
 
 
 
 
Productive (1)
 
30

 
30

 
19

 
30

 
30

 
19

Dry
 

 

 

 

 

 

 
 
30

 
30

 
19

 
30

 
30

 
19


(1)
Although a well may be classified as productive upon completion, future changes in oil and natural gas prices, operating costs and production may result in the well becoming uneconomical, particularly exploratory wells for which there is no production history.

In 2019, we drilled 18 gross (18 net) wells in our Northern Delaware Basin leasehold acreage and 9 gross (9 net) wells in our Southern Delaware Basin leasehold acreage. As of December 31, 2019, we had 1 operated well drilling and 5 DUCs. On March 19, 2020, we announced that we halted future drilling and completions activity for 2020 and had drilled 8 wells and completed 8 wells to date in 2020.

Productive wells

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2019. This table does not include wells in which we own a royalty interest only.
 
Gross Productive Wells
 
Net Productive Wells
 
Oil 
 
 
Natural
Gas
 
 
Total 
 
 
Oil 
 
 
Natural
Gas
 
Total 
 

 

 
 

 
 

 
 

 
 

 
 

Northern Delaware Basin
74

 
13

 
87

 
70

 
13

 
83

Southern Delaware Basin
26

 
3

 
29

 
25

 
3

 
28

Total
100

 
16

 
116

 
95

 
16

 
111

 
As of December 31, 2019, we had an average working interest of 95.7% in our productive wells. Productive wells consist of producing wells and wells capable of production, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest and net wells are the sum of our fractional working interests owned in gross wells.

Our acreage

The following table sets forth information as of December 31, 2019 relating to our Delaware Basin leasehold acreage.
 
 
Developed Acres
 
Undeveloped Acres
 
Total Acres

 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Delaware Basin
 
4,625

 
3,041

 

 

 
4,625

 
3,041

Southern Delaware Basin
 
6,935

 
6,609

 
4,225

 
3,569

 
11,160

 
10,178

    Total
 
11,560

 
9,650

 
4,225

 
3,569

 
15,785

 
13,219


53




We are the operator of approximately 97.2% of our net acreage. In addition, we own mineral interests underlying approximately 15,785 gross (13,219 net) of these acres, of which approximately 2,000 gross and net acres are subject to a farm-in agreement, with an average royalty interest of 76.6% in our net acres.

Undeveloped acreage expirations

Many of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth the gross and net undeveloped acreage, as of December 31, 2019, that will expire over the next five years unless production is established within the spacing units covering the acreage or the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates. On March 19, 2020, we announced a halt in our drilling program. We lost 321 net acres during the first quarter of 2020 and estimate that we will lose approximately 2,638 net acres, of which approximately 2,000 net acres relate to unearned acreage from a farm-in agreement that we must drill and complete the remaining 5 wells in order to retain the acreage, in the remainder of 2020 if we do not resume drilling during 2020.
 
 
2020
 
2021
 
2022
 
2023
 
2024
Expirations
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Northern Delaware Basin
 

 

 

 

 

 

 

 

 

 

Southern Delaware Basin
 
3,355

 
2,959

 
960

 
320

 

 

 

 

 

 

    Total
 
3,355

 
2,959

 
960

 
320

 

 

 

 

 

 


Title to properties

We believe that we have satisfactory title to our producing properties in accordance with generally accepted industry standards. As is customary in the oil and natural gas industry, we initially conduct only a cursory review of the title to our properties for an acquisition of leasehold acreage. We perform a thorough title examination and curative work with respect to significant defects either prior to an acquisition of producing properties or prior to commencement of drilling operations on those properties. 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. We have obtained title opinions on substantially all of our producing 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.

Prior to completing an acquisition of producing oil and natural gas leases, we perform title reviews on the most significant leases and, depending on the materiality of properties, we may obtain a title opinion, obtain an updated title review or opinion or review previously obtained title opinions. Our oil and natural gas properties are subject to customary royalty and other interests, liens for current taxes and other burdens, which we believe do not materially interfere with the use of or affect our carrying value of the properties.

We believe that we have satisfactory title to all our material assets. Although title to these properties is in some cases subject to encumbrances, such as customary interests generally retained in connection with the acquisition of real property, customary royalty interests and contract terms and restrictions, liens under operating agreements, liens related to environmental liabilities associated with historical operations, liens for current taxes and other burdens, easements, restrictions and minor encumbrances customary in the oil and natural gas industry, we believe that none of these liens, restrictions, easements, burdens and encumbrances will materially detract from the value of these properties or from our interest in these properties or materially interfere with our use of these properties in the operation of our business. In addition, we believe that we have obtained sufficient rights-of-way grants and permits from public authorities and private parties for us to operate our business in all material respects.

ITEM 3. LEGAL PROCEEDINGS
 
From time to time, we are subject to various legal proceedings arising in the ordinary course of business, including proceedings for which we have insurance coverage. We do not believe the results of any legal proceedings, individually or in the aggregate, will have a material adverse effect on our business, financial condition, results of operations or liquidity.

ITEM 4. MINE SAFETY DISCLOSURES
 
None.

54



PART II

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

Market Information

Our Class A Common Stock, Public Warrants and Units are currently quoted on Nasdaq under the symbols “ROSE,” “ROSEW” and “ROSEU,” respectively. Through April 26, 2017, our Class A Common Stock was quoted under the symbol “KLRE.” There is no public market for our Class B Common Stock.

Holders of Record

Approximately 16 registered stockholders of record held our Class A Common Stock as of March 27, 2020. This number does not include owners or stockholders who beneficially own our shares through a broker or other entity who may hold shares in a “street name.” On March 27, 2020, we had one holder of record of our Class B Common Stock.

Dividend Policy

We have not paid any cash dividends on our Class A Common Stock to date and do not currently contemplate paying dividends in the foreseeable future. The payment of cash dividends in the future will be dependent upon our revenues and earnings, if any, capital requirements and general financial condition. The payment of any future cash dividends will be within the discretion of our board of directors.

Pursuant to the Series A Certificate of Designation, holders of Series A Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends, payable in cash, Series A Preferred Stock, or a combination thereof, in each case, at the sole discretion of the Company, at an annual rate of 8% on the $1,000 liquidation preference per share of the Series A Preferred Stock, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on July 15, 2017.

Pursuant to the Series B Certificate of Designation, holders of Series B Preferred Stock are entitled to receive, when, as and if declared by our board of directors, cumulative dividends, payable in cash, or with respect to dividends declared for any quarter ending on or prior to January 15, 2019, a combination of cash and Series B Preferred Stock, in each case, at the sole discretion of the Company, at an annual rate of 10% on the $1,000 liquidation preference per share of the Series B Preferred Stock, payable quarterly in arrears on January 15, April 15, July 15 and October 15 of each year, beginning on January 15, 2018.

Issuer Purchases of Equity Securities
Period
 
Total Number of Shares Purchased (1)
 
Average Price Paid per Share
 
Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs
 
Maximum Dollar Value of Shares that May Yet Be Purchased Under the Plans or Programs
October 1, 2019 - October 31, 2019
 
1,141

 
$
1.46

 
n/a
 
n/a
November 1, 2019 - November 30, 2019
 

 

 
n/a
 
n/a
December 1, 2019 - December 31, 2019
 

 

 
n/a
 
n/a
Total
 
1,141

 
$
1.46

 
n/a
 
n/a

(1)
These shares were withheld upon the vesting of employee restricted stock grants in connection with payment of required withholding taxes.

ITEM 6. SELECTED FINANCIAL DATA

We are a smaller reporting company as defined by Rule 12b-2 of the Exchange Act and are not required to provide the information under this item.

55



ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
 
The following discussion and analysis should be read in conjunction with the consolidated financial statements and notes thereto appearing elsewhere in this Annual Report on Form 10-K. The following discussion contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside of our control. Such statements speak only as of the date of this report. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, market prices for oil, natural gas and NGLs, production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, regulatory changes and other uncertainties, as well as those factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Risk Factors” and “Cautionary Statement Regarding Forward-Looking Statements,” all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur.

Overview

We are an independent oil and natural gas company focused on the acquisition, exploration, development and production of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. We have drilling locations in ten distinct formations in the Delaware Basin in: Brushy Canyon, Upper Avalon, Lower Avalon, 2nd Bone Spring Shale, 2nd Bone Spring Sand, 3rd Bone Spring Sand, 3rd Bone Spring Shale, Wolfcamp A (X/Y), Lower Wolfcamp A and Wolfcamp B, and our goal is to build a premier development and acquisition company focused on horizontal drilling in the Delaware Basin.
We have no direct operations and no significant assets other than our ownership interest in Rosehill Operating, an entity of which we act as the sole managing member and of whose common units we currently own approximately 64.5% (or 70.6% assuming the conversion of Rosehill Operating Series A Preferred Units into Rosehill Operating Common Units).

Market Conditions

The oil and natural gas industry is cyclical and commodity prices are highly volatile. Oil prices have recently reached multi-year lows. For example, for the three years ended December 31, 2017, 2018, and 2019, WTI spot prices for crude oil had a low of $42.48 per barrel during June 2017 and a high of $77.41 per barrel during June 2018, while the average in 2019 was approximately $56.98 per barrel. As of March 27, 2020, WTI spot prices for crude oil were $21.84 per barrel. For the three years ended December 31, 2017, 2018, and 2019, Henry Hub spot prices for natural gas had a low of $1.75 per MMBtu during December 2019 and a high of $6.24 per MMBtu during January 2018, while the average in 2019 was approximately $2.56 per MMBtu. As of March 27, 2020, Henry Hub spot prices for natural gas were $1.67 per MMBtu. It is likely that commodity prices will continue to fluctuate and possibly further, decline due to global supply and demand, inventory supply levels, weather conditions, geopolitical events, the COVID-19 pandemic and other factors. Due to these and other unprecedented factors, commodity prices cannot be accurately predicted.

On March 19, 2020, we announced that we have ceased drilling and completion activity.

Realized Prices

Our revenue, profitability and future growth are highly dependent on the prices we receive for our oil and natural gas production, as well as NGLs that are extracted from our natural gas during processing. The following table presents our average realized commodity prices before the effects of commodity derivative settlements:
 
Year Ended December 31,
 
2019
 
2018
 
2017
Crude oil (per Bbl)
$
52.99

 
$
55.27

 
$
48.46

Natural gas (per Mcf)
$
0.39

 
$
1.80

 
$
2.65

NGLs (per Bbl)
$
11.71

 
$
23.07

 
$
18.31


Current 2020 forward pricing will likely result in impairments of our properties during the first quarter of 2020 and may materially and adversely affect our future business, financial condition, results of operations, operating cash flows, liquidity, or ability to finance planned capital expenditures. Lower oil, natural gas and NGL prices may also reduce the borrowing base under our Amended and Restated Credit Agreement, which may be redetermined at the discretion of the lenders and is based on the

56



collateral value of our proved reserves that have been mortgaged to the lenders. The next redetermination is scheduled for April 2020. Alternatively, higher oil, natural gas and NGL prices may result in significant losses being incurred on our commodity derivatives, which could cause us to experience net losses when oil and natural gas prices rise. For 2019, we received low prices for our natural gas due to lower NYMEX gas prices, wider gas price differentials and due to the adoption of ASC 606. Because we receive revenue from NGLs, we have and may continue to produce and sell our natural gas at a low, or negative, realized sales price. The widening gas price differentials were due to pipeline takeaway capacity constraints in the Permian Basin, but the industry expects new pipelines to come online to help with this constraint and help provide relief to the widening gas price differentials.

A 10% change in our realized oil, natural gas and NGL prices would have changed revenue by the following amounts for the periods indicated:
 
Year Ended December 31,
 
2019
 
2018
 
2017
 
(In thousands)
Oil sales
$
28,671

 
$
27,154

 
$
6,160

Natural gas sales
249

 
939

 
717

NGL sales
1,308

 
2,094

 
747

Total revenues
$
30,228

 
$
30,187

 
$
7,624


The prices we receive for our products are based on benchmark prices and are adjusted for quality, energy content, transportation fees and regional price differentials. See “Results of Operations” below for an analysis of the impact changes in realized prices had on our revenues. 

Sources of Our Revenues
 
Our revenues are derived from the sale of our oil and natural gas production, as well as the sale of NGLs that are extracted from our natural gas during processing. The following table shows the percentage each component contributed to total revenue:
 
Year Ended December 31,
Commodity Revenues (1):
2019
 
2018
 
2017
Oil sales
95
%
 
90
%
 
81
%
Natural gas sales
1

 
3

 
9

NGL sales
4

 
7

 
10

 
100
%
 
100
%
 
100
%

(1)
The percentages exclude the effects of commodity derivatives.

Gateway, a related party to us, accounted for none of our revenues for the year ended December 31, 2019 and approximately 60% and 80% of total revenues for the years ended December 31, 2018 and 2017, respectively.

Derivative Activity

To achieve a more predictable cash flow and reduce exposure to adverse fluctuations in commodity prices, we have historically used commodity derivative instruments, such as swaps, two-way costless collars and three-way costless collars, to hedge price risk associated with a portion of our anticipated oil, natural gas and NGL production. By removing a significant portion of the price volatility associated with our production, we will mitigate, but not eliminate, the potential negative effects of declines in benchmark oil, natural gas and NGL prices on our cash flow from operations for those periods. However, for a portion of our current positions, hedging activity may also reduce our ability to benefit from increases in oil, natural gas and NGL prices. We will sustain losses to the extent our commodity derivative contract prices are lower than market prices and, conversely, we will sustain gains to the extent our commodity derivative contract prices are higher than market prices. In certain circumstances, where we have unrealized gains in our commodity derivatives portfolio, we may choose to restructure existing commodity derivative contracts or enter into new transactions to modify the terms of current contracts in order to realize the current value of our existing positions.


57



A description of our derivative financial instruments is provided below:

A swap has an established fixed price. When the settlement price is below the fixed price, the counterparty pays us an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract volume. When the settlement price is above the fixed price, we pay our counterparty an amount equal to the difference between the settlement price and the fixed price multiplied by the hedged contract value.

A two-way costless collar is an arrangement that contains a fixed floor price (purchased put option) and a fixed ceiling price (sold call option) based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the ceiling price, we pay the counterparty the difference between the index price and ceiling price, (2) if the index price is between the floor and ceiling prices, no payments are due from either party and (3) if the index price is below the floor price, we will receive the difference between the floor price and the index price.

A three-way costless collar is an arrangement that contains a purchased put option, a sold call option and a sold put option based on an index price which, in aggregate, have no net cost. At the contract settlement date, (1) if the index price is higher than the sold call strike price, we pay the counterparty the difference between the index price and sold call strike price, (2) if the index price is between the purchased put strike price and the sold call strike price, no payments are due from either party, (3) if the index price is between the sold put strike price and the purchased put strike price, we will receive the difference between the purchased put strike price and the index price and (4) if the index price is below the sold put strike price, the Company will receive the difference between the purchased put strike price and the sold put strike price.

A purchased put option has an established floor price. The buyer of the put option pays the seller a premium to enter into the put option. When the settlement price is below the floor price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is above the floor price, the put option expires worthless.

A sold call option has an established ceiling price. The buyer of the call option pays the seller a premium to enter into the call option. When the settlement price is above the ceiling price, the seller pays the buyer an amount equal to the difference between the settlement price and the strike price multiplied by the hedged contract volume. When the settlement price is below the ceiling price, the call option expires worthless.


58



We had a net current asset of $6.5 million and a net non-current asset of $32.7 million related to the following open commodity derivative instrument positions as of December 31, 2019: