Summary of Significant Accounting Policies and Recently Issued Accounting Standards (Policies)

12 Months Ended

Dec. 31, 2019

The consolidated financial results of the Company consist of the financial results of Rosehill and Rosehill Operating, its consolidated subsidiary. As of December 31, 2019, the Company owns approximately 64.5% of the common units of Rosehill Operating (the “Rosehill Operating Common Units”) and Tema owns approximately 35.5% of the Rosehill Operating Common Units.

The Transaction was accounted for as a reverse recapitalization. As a result, the reports filed by the Company subsequent to the Transaction are prepared “as if” Rosehill Operating is the predecessor and legal successor to the Company. The historical operations of Rosehill Operating are deemed to be those of the Company. Thus, the financial statements included in this report reflect (i) the historical operating results of Rosehill Operating prior to the Transaction; (ii) the combined results of the Company and Rosehill Operating following the Transaction; (iii) the assets and liabilities of Rosehill Operating at their historical cost; and (iv) the Company’s equity and earnings per share for all periods presented.

All periods during the year ended December 31, 2017 that occurred prior to the date of the Transaction were prepared on a “carve-out” basis and are derived from the accounting records of Tema. The accompanying consolidated financial statements prior to the Transaction include direct expenses related to Rosehill Operating and expense allocations for certain functions of Tema including, but not limited to, general corporate expenses related to finance, legal, information technology, human resources, communications, insurance, utilities and compensation. These expenses have been allocated on the basis of direct usage when identifiable, actual volumes and revenues, with the remainder allocated proportionately on a barrel of oil equivalent (“Boe”) basis. Management considers the basis on which the expenses have been allocated to reasonably reflect the utilization of services provided to or the benefit received by Rosehill Operating during the periods presented. The allocations may not, however, reflect the expenses that would have been incurred as an independent company for the periods presented. Actual costs that may have been incurred prior to the Transaction would depend on a number of factors, including the organizational structure, whether functions were outsourced or performed by employees and strategic decisions made in areas such as information technology and infrastructure. The allocations and related estimates and assumptions are described more fully in Note 16 - Transactions with Related Parties.

The consolidated financial statements of the Company have been prepared in accordance with generally accepted accounting principles in the United States (“U.S. GAAP”). All intercompany balances and transactions have been eliminated in consolidation. Certain prior period amounts have been reclassified to conform to the current presentation on the accompanying consolidated financial statements. Such reclassifications had no impact on net income, cash flows or shareholders’ equity previously reported.

Variable Interest Entities

Rosehill Operating is a variable interest entity. The Company determined that it is the primary beneficiary of Rosehill Operating as the Company is the sole managing member and has the power to direct the activities most significant to Rosehill Operating’s economic performance as well as the obligation to absorb losses and receive benefits that are potentially significant. The Company consolidated 100% of Rosehill Operating’s assets and liabilities and results of operations in the Company’s consolidated financial statements. For further discussion, see Noncontrolling Interest in Note 14 - Stockholders’ Equity.

Use of Estimates

The preparation of the Company’s consolidated financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues, expenses and in the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts previously reported. The more significant areas requiring the use of assumptions, judgments and estimates include:


•	the quantities and values of proved oil, natural gas and natural gas liquids (“NGLs”) reserves used in calculating depletion and assessing impairment of oil and natural gas properties and related present value estimates of future net cash flows therefrom,


•	the carrying value of oil and natural gas properties;


•	asset retirement obligations;


•	the fair value of commodity derivative instruments and positions;


•	estimates of the fair value of equity-based compensation;


•	accrued revenue and related receivables;


•	accrued capital expenditures;


•	estimates of current and deferred income taxes and


•	deferred income tax valuation allowances and amounts associated with the Company’s Tax Receivable Agreement with Tema (the “Tax Receivable Agreement”) (see Note 13 – Income Taxes).

While management believes these estimates are reasonable, changes in facts and assumptions, or the discovery of new information may result in revised estimates. Actual results could differ from these estimates and it is reasonably possible these estimates could be revised in the near term, and these revisions could be material.

Cash and Cash Equivalents

The Company considers all cash on hand, and highly liquid instruments with an original maturity of three months or less to be cash and cash equivalents. The Company’s cash and cash equivalents are held in financial institutions in amounts that may exceed the insurance limits of the Federal Deposit Insurance Corporation, however, management believes the Company’s counter-party risks are minimal based on the reputation and history of the institutions selected.

Accounts Receivable

Accounts receivable consist of receivables from joint interest owners on properties the Company operates and from sales of oil and natural gas production delivered to purchasers. The purchasers remit payment for production directly to the Company. Most payments are received within three months after the production date. Accounts receivable are not collateralized.

Amounts due from joint interest owners or purchasers are stated net of an allowance for doubtful accounts when the Company believes collection is doubtful. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover any non-payment of joint interest billings. Accounts receivable outstanding longer than the contractual payment terms are considered past due. The Company determines its allowance by considering a number of factors, including the length of time accounts receivable are past due, the Company’s previous loss history, the debtor’s current ability to pay its obligation to the Company, the condition of the general economy and the industry as a whole. The Company writes off specific accounts receivable when they become uncollectible, and payments subsequently received on such receivables are credited to the allowance for doubtful accounts. No allowance was deemed necessary at December 31, 2019 and 2018. See details of the Company’s accounts receivable balance in Note 5 - Accounts Receivable.

Revenue Recognition

The Company recognizes oil, natural gas and NGL revenue at the point in time when control of the product transfers to the customer, which differs depending on the contractual terms of each of the Company’s arrangements. Transfer of control drives the presentation of gathering, transportation, processing and other post-production expenses (“gathering and transportation expense”) within the Company’s Consolidated Statements of Operations. In these scenarios below, the Company evaluates whether it is the principal or the agent in the transaction and the analysis includes considerations of product redelivery, take-in-kind rights and risk of loss. For those contracts where the Company has concluded that control of the product transfers at the tailgate of the plant, meaning that the Company is the principal and the ultimate third party purchaser is its customer, the Company recognizes revenue on a gross basis, with transportation, processing and gathering expenses presented within the Gathering and transportation line item on the Company’s Consolidated Statements of Operations. Alternatively, for those contracts where the Company has concluded control of the product transfers at or near the wellhead or inlet of the plant, meaning that the Company is the agent and the midstream processing company is the Company’s customer, the Company recognizes natural gas and NGL revenues based on the net amount of proceeds received from the midstream processing company. See Note 18— Revenue from Contracts with Customers for more detail on the Company’s revenue recognition and the impact of ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”).

Oil and Natural Gas Activities, Impairment, and Reserve Quantities

Successful Efforts Method of Accounting for Oil and Natural Gas Activities

Oil and natural gas exploration, development and production activities are accounted for under the successful efforts method of accounting. Under this method, the costs incurred to acquire, drill and complete productive wells and development wells are capitalized. Oil and gas lease acquisition costs are also capitalized.

Proved Oil and Natural Gas Properties. If proved reserves are found for these properties, costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells and service wells, including unsuccessful development wells, are capitalized. Capitalized costs attributed to the properties and mineral interests are subject to depreciation, depletion and amortization (“DD&A”). Depletion of capitalized costs is provided using the units-of-production method based on proved oil and gas reserves related to the associated reservoir. If no proved reserves have been found, the costs of each of the related exploratory wells are charged to expense.

Unproved Properties. Acquisition costs associated with the acquisition of non-producing leaseholds are recorded as unproved leasehold costs and capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or right in a property, such as a lease in addition to options to lease, broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered, at which time related costs are transferred to proved oil and natural gas properties.

Exploration Costs. Exploration costs, other than exploration drilling costs, are charged to expense as incurred. These costs include personnel and other internal costs, geological and geophysical expenses, exploratory dry holes, delay rentals for leases and cost associated with unsuccessful lease acquisitions. The costs of drilling exploratory wells and exploratory-type stratigraphic wells are initially capitalized pending determination of whether the well has discovered proved commercial reserves. If the exploratory well is determined to be unsuccessful, the cost of the well is transferred to expense.

In some cases, a determination of proved reserves cannot be made at the completion of drilling, requiring additional testing and evaluation of the wells. The costs of such exploratory wells are expensed if a determination of proved reserves has not been made within a 12-month period after drilling is complete.

For sales of a complete or partial unit of proved and unproved properties and related facilities, the cost and related accumulated DD&A are removed from the property accounts and gain or loss is recognized for the difference between the proceeds received and the net carrying value of the properties sold.

Impairment of Oil and Natural Gas Properties

The Company’s proved oil and natural gas properties are recorded at cost. The Company’s proved properties are evaluated for impairment on a field-by-field basis whenever events or changes in circumstances indicate that an asset’s carrying value may not be recoverable. The Company compares expected undiscounted future cash flows to the net book value of the asset. If the future undiscounted expected cash flows, based on its estimate of future oil and natural gas prices, operating costs and anticipated production from proved reserves and risk-adjusted probable and possible reserves, are lower than the net book value of the asset, the capitalized cost is reduced to fair value. Commodity pricing is estimated by using WTI and Henry Hub natural gas NYMEX strip market pricing, adjusted for quality, transportation fees and a regional price differential. Fair value is calculated by discounting the future cash flows at a rate of 10%. The Company believes a 10% discount rate is commonly used by oil and gas industry peers, analysts and investors in evaluating the monetary significance of oil and gas properties and for comparing the size and value of proved reserves among companies in our industry. Accordingly, the Company currently believes a 10% discount rate is consistent with a rate a market participant would consider in evaluating onshore domestic proved oil and gas reserves and produces a reasonable estimate of fair value.

Unproved oil and natural gas properties are assessed periodically, and no less than annually, for impairment on an aggregate basis based on remaining lease term, drilling results, reservoir performance, seismic interpretation and future plans to develop acreage. As unproved oil and natural gas properties are developed and reserves are proved, the capitalized costs are subject to depreciation and depletion. If the development of these properties is deemed unsuccessful, the capitalized costs related to the unsuccessful activity is expensed in the year the determination is made. The rate at which the unproved oil and natural gas properties are written off or reclassified to proved oil and natural gas properties depends on the timing and success of the Company’s future exploration and development program.

The Company expects the decline in oil prices that occurred subsequent to December 31, 2019 to significantly reduce the undiscounted expected cash flows from its proved reserves and will more than likely result in impairments of the Company’s proved properties during the first quarter of 2020. If oil prices continue to decrease subsequent to March 2020, additional impairments of the Company’s properties will be recorded. Due to the Company suspending its drilling and completion program for 2020, it expects to lose a portion of its acreage through lease expirations that will result in material impairments recorded in 2020 related to those expirations.

Oil and Natural Gas Reserve Quantities

The Company’s estimated proved reserve quantities and future net cash flows are critical to the understanding of the value of its business. They are used in comparative financial ratios and are the basis for significant accounting estimates in its financial statements, including the calculations of depletion and impairment of proved oil and natural gas properties. Future cash inflows and future production and development costs are determined by applying prices and costs, including transportation, quality differentials and basis differentials, applicable to each period to the estimated quantities of proved reserves remaining to be produced as of the end of that period. Expected cash flows are discounted to present value using an appropriate discount rate. For example, the standardized measure calculations require a 10% discount rate to be applied. Although reserve estimates are inherently imprecise, and estimates of new discoveries and undeveloped locations are more imprecise than those of established producing oil and gas properties, the Company makes a considerable effort in estimating our reserves. The Company expects proved reserve estimates will change as additional information becomes available and as commodity prices and operating and capital costs change. The Company has and expects to evaluate and estimate its proved reserves each year-end. For purposes of depletion and impairment, reserve quantities are adjusted in accordance with U.S. GAAP for the impact of additions and dispositions.

Other Property and Equipment

Other property and equipment such as office furniture and equipment, buildings, computer hardware and software is recorded at cost. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets ranging from three to twenty years. Major renewals and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts.

Asset Retirement Obligation

Asset Retirement Obligations

An asset retirement obligation (“ARO”) represents the estimated present value of the amount a company will incur to retire a long-lived asset at the end of its productive life, in accordance with applicable state laws. The Company recognizes an estimated liability for future costs primarily associated with the abandonment of its oil and natural gas properties and related assets. The amount of the ARO is determined by calculating the present value of estimated cash flows related to the liability. The retirement obligation is recorded as a liability at its estimated present value at inception (i.e. at the time the well is drilled or acquired and related assets are placed into service) with an offsetting increase in the carrying amount of the related long-lived asset that is included in proved oil and natural gas properties in the accompanying consolidated balance sheets. Periodic accretion of discount of the estimated liability is recorded as an expense in the consolidated statement of operations. The Company depreciates the long-lived asset, including the asset retirement cost, over its useful life, and recognizes expense in connection with the accretion of the discounted liability over the remaining estimated economic lives of the respective oil and natural gas properties.

An asset retirement liability is determined using significant assumptions, including current estimates of plugging and abandonment costs, annual inflation of these costs, the productive lives of assets and the Company’s risk-adjusted interest rate. Changes in any of these assumptions can result in significant revisions to the estimated asset retirement obligation. Because of the subjectivity of assumptions, the costs to ultimately retire the Company’s wells may vary significantly from prior estimates. See Note 9 - Asset Retirement Obligations for more detail of our ARO activity.

Deferred Financing Costs

Deferred financing costs and discounts related to the Company’s Revolving Credit Facility and its Second Lien Notes are included in other long-term assets and long-term debt, respectively, in the consolidated balance sheets and are stated at cost, net of amortization. The deferred financing costs associated with the Revolving Credit Facility and the Second Lien Notes are amortized to interest expense on a straight-line basis and an effective rate of interest method, respectively, over the borrowing terms. See Note 11 - Long term debt, net for more detail.

Derivative Instruments

The Company utilizes commodity derivative instruments including swaps, collars, basis swaps and other similar agreements to manage its exposure to oil, natural gas and NGL price volatility (i.e., price risk) associated with the forecasted sale of a portion its oil and natural gas production. The Company utilizes interest rate swaps to manage its exposure to London Inter-bank Offered Rate (LIBOR) volatility associated with a portion of its outstanding borrowing under its Amended and Restated Credit Agreement. These derivative instruments are not designated as hedges for accounting purposes. Accordingly, the Company records derivative instruments on the consolidated balance sheets as either an asset or liability measured at fair value and records changes in the fair value of derivatives in current earnings in the consolidated statements of operations as they occur in the period of change. Gains and losses on commodity derivatives and cash premiums paid for put options are included in cash flows from operating activities.

To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis. The Company has exposure to credit risk to the extent the counterparty is unable to satisfy its settlement obligation. The Company actively monitors the creditworthiness of counterparties and assesses the impact, if any, on its derivative position. See Note 6 - Derivative Instruments for a further discussion.

Fair Value of Financial Instruments

Fair value represents the price that would be received to sell the asset or paid to transfer the liability in an orderly transaction between market participants at the reporting date. The Company’s assets and liabilities that are measured at fair value at each reporting date are classified according to a hierarchy that prioritizes inputs and assumptions underlying the valuation techniques. This fair value hierarchy gives the highest priority to quoted prices in active markets for identical assets or liabilities and the lowest priority to unobservable inputs and consists of three broad levels:



Level 1:	Observable inputs that reflect unadjusted quoted prices for identical assets or liabilities in active markets as of the reporting date.
Level 2:	Observable market-based inputs or unobservable inputs that are corroborated by market data. These are inputs other than quoted prices in active markets included in Level 1 that are either directly or indirectly observable as of the reporting date.
Level 3:	Unobservable inputs that are not corroborated by market data and may be used with internally developed methodologies that result in management’s best estimate of fair value.

Valuation techniques that maximize the use of observable inputs are favored. Observable data is considered to be market data if it is readily available, regularly distributed or updated, reliable and verifiable, not proprietary, and provided by multiple, independent sources that are actively involved in the relevant market. In certain cases, the inputs used to measure fair value may fall into different levels of the fair value hierarchy. In such cases, an investment’s level within the fair value hierarchy is based on lowest level of input that is significant to the fair value measurement. The assessment of the significance of a particular input to the fair value measurement in its entirety requires judgment and considers factors specific to the investment. However, the determination of what constitutes “observable” requires significant judgment. The categorization of an investment within the hierarchy is based upon the pricing transparency of the investment and does not necessarily correspond to the perceived risk of that investment. Reclassifications of fair value between Level 1, Level 2 and Level 3 of the fair value hierarchy, if applicable, are made at the end of each quarter. See Note 7 – Fair Value Measurements for more fair value disclosures.

Income Taxes

Deferred tax assets and liabilities are recognized for the estimated future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases. Deferred tax assets and liabilities are calculated by applying existing tax laws and the rates expected to apply to taxable income in the years in which those temporary differences are expected to be recovered or settled. The effect of a change in tax rates on deferred tax assets and liabilities is recognized in the year of the enacted rate change.

The Company accounts for uncertainty in income taxes using a recognition and measurement threshold for tax positions taken or expected to be taken in a tax return, which are subject to examination by federal and state taxing authorities. The tax benefit from an uncertain tax position is recognized when it is more likely than not that the position will be sustained upon examination by taxing authorities based on technical merits of the position. The amount of the tax benefit recognized is the largest amount of the benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. The effective tax rate and the tax basis of assets and liabilities reflect management’s estimates of the ultimate outcome of various tax uncertainties. The Company recognizes penalties and interest related to uncertain tax positions within the provision (benefit) for income taxes line in the accompanying consolidated statements of operations.

The Company is a C corporation and is subject to U.S. federal, state and local income taxes. Rosehill Operating is a limited liability company treated as a partnership for U.S. federal income tax purposes that is generally not subject to U.S. federal income tax at the entity level.

Earnings (Loss) Per Share

The two-class method of computing earnings per share is required for entities that have participating securities. The two-class method is an earnings allocation formula that determines earnings per share for participating securities according to dividends declared (or accumulated) and participation rights in undistributed earnings. Our Class B Common Stock has no economic interest in the earnings of the Company, thus is not considered a participating security.

Basic earnings (loss) per common share (“EPS”) is calculated by dividing net income (loss) attributable to Class A Common Stock holders by the weighted average number of shares of Class A Common Stock outstanding each period. Dilutive EPS is calculated by dividing adjusted net income (loss) attributable to Class A Common Stock holders by the weighted average number of shares of Class A Common Stock outstanding each period, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) the Company’s Class B Common Stock, (ii) Series A Preferred Stock, (iii) warrants for Class A Common Stock and (iv) the vesting of unvested restricted stock units of Class A Common Stock.

The Company uses the “if-converted” method to determine the potential dilutive effect of conversions of its outstanding Class B Common Stock and Series A Preferred Stock, and the treasury stock method to determine the potential dilutive effect of its outstanding warrants exercisable for shares of Class A Common Stock and the vesting of unvested restricted stock units of Class A Common Stock. See Note 4 - Earnings (Loss) Per Share for the Company’s earnings (loss) per share calculation.

Accounting Standards Adopted and Recently Issued and Not Yet Adopted

Accounting Standard Adopted in 2019

Revenue Recognition. ASU 2014-09, Revenue from Contracts with Customers (Topic 606) (“ASC 606”), supersedes the revenue recognition requirements in Topic 605, Revenue Recognition, and industry-specific guidance in Subtopic 932-605, Extractive Activities-Oil and Gas-Revenue Recognition and requires an entity to recognize revenue when it transfers promised goods or services to customers in an amount that reflects the consideration the entity expects to be entitled to in exchange for those goods or services. In May 2016, the FASB issued ASU 2016-12, Revenue from Contracts with Customers (Topic 606): Narrow-Scope Improvements and Practical Expedients, as clarifying guidance to improve the operability and understandability of the implementation guidance on principal versus agent considerations.

Because the Company is an emerging growth company, ASC 606 became effective for the Company on January 1, 2019, and the Company elected to adopt it using the modified retrospective method. The Company completed its review of the impact of ASC 606 on its significant contracts and determined that the Company was not required to record a cumulative effect adjustment to retained earnings. The implementation of ASC 606 did result in changes to the presentation of “Revenues” and “Gathering and transportation” on the Company’s Consolidated Statement of Operations, but there was no impact to net income. See Note 18 - Revenue from Contracts with Customers.

Recently Issued Accounting Standards Not Yet Adopted

Leases. In February 2016, the FASB issued ASU 2016-02, Leases (Topic 842), which requires the recognition of lease assets and lease liabilities by lessees for those leases classified as operating leases under current U.S. GAAP. In January 2018, the FASB issued ASU 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842, which provides clarifying guidance regarding land easements and adds practical expedients. In July 2018, further amendments were issued under ASU 2018-10, Codification Improvements to Topic 842, Leases. In July 2018, the FASB issued ASU 2018-11, Leases (Topic 842): Targeted Improvements, which provides entities with an additional transition method in which an entity initially applies the new leases standard at the adoption date and recognizes a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. ASU 2016-02 and its related updates are effective for the Company for fiscal years beginning after December 15, 2019.

The Company has substantially completed the process of reviewing and determining contracts to which the new guidance applies. The Company elected the following practical expedients: (a) for agreements that contain both lease and non-lease components, combining these components together and accounting for them as a single lease, (b) the package of practical expedients which allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy U.S. GAAP and (c) excluding land easements that existed or expired before adoption. Additionally, the Company has made an accounting policy election to keep leases with an initial term of 12 months or less off of the Consolidated Balance Sheets. The Company adopted ASU 2016-02 on January 1, 2020 using the modified retrospective approach, and the adoption of the standard is expected to result in the recognition of approximately $2.1 million of right-of-use assets and $2.6 million of lease liabilities, with the entire amount relating to our operating leases.

Fair Value Measurement Disclosures. In August 2018, the FASB issued ASU 2018-13, Fair Value Measurement (Topic 820): Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds disclosure requirements on fair value measurements. ASU 2018-13 is effective for the Company for fiscal years beginning after December 15, 2019 and the Company plans to adopt it on January 1, 2020. The Company is still evaluating the impact of the adoption of this guidance on its disclosures but may be required to add disclosure on the range and weighted average of significant unobservable inputs used to measure its Series B Preferred Stock bifurcated derivative, which is a Level 3 disclosure.