The consolidated financial statements include the accounts of the Company. All significant intercompany balances and transactions have been eliminated in consolidation. The consolidated financial statements included herein were prepared from the records of the Company in accordance with GAAP, the instructions to Form 10-K, and Regulation S-X. Additionally, certain prior period amounts have been reclassified to conform to current period presentation in the accompanying financial statements. During the current year, the Company is separately presenting Production taxes payable on the accompanying balance sheets. Accordingly, prior year amounts have been reclassified from Accounts payable and accrued expenses to conform to current year presentation.

The preparation of the consolidated financial statements in conformity with GAAP requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, as well as the disclosure of contingent assets and liabilities and commitments as of the date of our financial statements. Actual results could differ from those estimates.

The Company considers all highly liquid investments with original maturity dates of three months or less to be cash equivalents. The carrying value of cash and cash equivalents approximate fair value due to the short-term nature of these instruments. The Company maintains cash balances in excess of federal deposit insurance limits as of December 31, 2021 and 2020, potentially subjecting the Company to a concentration of credit risk. To mitigate this risk, we maintain our cash and cash equivalents in the form of money market and checking accounts with financial institutions that we believe are creditworthy and are also lenders under our Credit Facility.

The following table provides a reconciliation of cash, cash equivalents, and restricted cash reported within the accompanying balance sheets, which sums to the total of such amounts shown in the accompanying statements of cash flows (in thousands):


	As of December 31,
	2021		2020		2019
Cash and cash equivalents	$	254,454	$	24,743	$	11,008
Restricted cash(1)	102		102		87
Total cash, cash equivalents, and restricted cash	$	254,556	$	24,845	$	11,095

The Company’s accounts receivable primarily consists of receivables due from purchasers of the Company's oil, natural gas, and NGL production and from joint interest owners on properties the Company operates. The Company is exposed to credit risk in the event of nonpayment by the purchasers of its production and/or joint interest owners on the properties it operates, nearly all of which are concentrated in energy-related industries. The Company continuously evaluates the creditworthiness of the Company's purchasers and joint interest owners on the properties it operates. Generally, the Company’s oil, natural gas, and NGLs receivables are collected within one to two months. For receivables due from joint interest owners, the Company generally has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. The Company has historically experienced minimal bad debts.

The Company does not believe the loss of any single purchaser of its production would materially impact its financial position or results of operations, as oil, natural gas, and NGLs are products with well-established and highly liquid markets. For the periods presented below, the following purchasers of the Company's production accounted for more than 10% of the Company's revenue as follows:

Proved Properties. The Company accounts for its oil and natural gas properties under the successful efforts method of accounting. Under this method, the costs of development wells are capitalized to proved properties whether those wells are successful or unsuccessful. Capitalized drilling and completion costs, including lease and well equipment, intangible development costs, and operational support facilities are depleted using the units-of-production method based on estimated proved developed reserves. Proved leasehold costs are also depleted; however, the units-of-production method is based on estimated total proved reserves. The computation of depletion expense takes into consideration restoration, dismantlement, and abandonment costs as well as the anticipated proceeds from salvaging equipment. Because all of our proved properties are currently located in a single field, we apply depletion on a single field basis. During the years ended December 31, 2021, 2020, and 2019, the Company incurred depletion expense of $212.5 million, $82.6 million, and $69.3 million, respectively.

The Company assesses proved properties for impairment whenever events or circumstances indicate that their carrying value may not be recoverable. If carrying values exceed undiscounted future net cash flows, impairment is measured and recorded at fair value. Because there usually is a lack of quoted market prices for proved properties, the Company estimates the fair value using valuation techniques that convert estimated future net cash flows to a single discounted amount. Significant inputs and assumptions to this estimation include, but are not limited to, reserves volumes, future operating and development costs, future commodity prices, inclusive of applicable differentials, and a market-based weighted average cost of capital rate. The expected future cash flows used for impairment reviews include future production volumes associated with proved developed producing reserves and risk-adjusted proved undeveloped reserves, and when needed, probable and possible reserves.

The partial sale of a proved property within an existing field is accounted for as a normal retirement and no net gain or loss on divestiture activity is recognized as long as such treatment does not significantly affect the units-of-production depletion rate. The sale of a partial interest in an individual proved property is accounted for as a recovery of cost. A net gain or loss on divestiture activity is recognized in the accompanying statements of operations for all other sales of proved properties.

Unproved properties are routinely evaluated for continued capitalization or impairment. On a quarterly basis, management assesses undeveloped leasehold costs for impairment by considering, among other things, remaining lease terms, future drilling plans and capital availability to execute such plans, commodity price outlooks, recent operational results, reservoir performance and geology, and estimated acreage value based on prices received for similar, recent acreage transactions by the Company or other market participants. Changes in our assumptions of the estimated nonproductive portion of our undeveloped leases could result in additional impairment expense. During the years ended December 31, 2021, 2020, and 2019, the Company incurred $57.3 million, $37.3 million, and $11.2 million, respectively, in abandonment and impairment of unproved properties.

Exploratory. Exploratory geological and geophysical, including exploratory seismic studies, and the costs of carrying and retaining unproved acreage are expensed as incurred. Under the successful efforts method of accounting, exploratory well costs are capitalized pending further evaluation of whether economically recoverable reserves have been found. If economically recoverable reserves are found, exploratory well costs will be capitalized as proved properties and will be accounted for following the successful efforts method of accounting described above. If economically recoverable reserves are not found, exploratory well costs are expensed as dry holes. The application of the successful efforts method of accounting requires judgment to determine the proper designation of wells as either development or exploratory, which will ultimately determine the proper accounting treatment of costs of dry holes. Once a well is drilled, the determination that economic proved reserves have been discovered may take considerable time and judgment. Exploratory dry hole costs are included in the cash flows from investing activities section as part of exploration and development of oil and natural gas properties within the accompanying statements of cash flows.

Oil and Natural Gas Reserves. The successful efforts method of accounting outlined above inherently relies on the estimation of proved oil and natural gas reserves. Reserve quantities and the related estimates of future net cash flows are critical inputs in our calculation of units-of-production depletion and our evaluation of proved and unproved properties for impairment. The process of estimating and evaluating crude oil and natural gas reserves is complex, requiring the evaluation of available geological, geophysical, engineering and economic data to estimate underground accumulations of oil and natural gas that cannot be precisely measured. Consequently, the Company engages a third-party petroleum consultant to prepare our estimates of oil and natural gas reserves. Significant inputs and engineering assumptions used in developing the estimates of proved oil and natural gas reserves include reserves volumes, future operating and development costs, historical commodity prices, and the Company’s ability to convert proved undeveloped reserves to producing properties within five years of their initial proved booking.

The data for a given property may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and a continual reassessment of the viability of production under changing economic conditions. As a result, revisions in existing reserve estimates occur. We cannot predict the amounts or timing of such future revisions. If such revisions are significant, they could significantly affect future amortization of capitalized costs and result in impairment of proved property.

Other property and equipment such as office furniture and equipment, buildings, and computer hardware and software are recorded at cost. Cost of renewals and improvements that substantially extend the useful lives of the assets are capitalized. Maintenance and repair costs are expensed as incurred. Depreciation is calculated using the straight-line method over the estimated useful lives of the assets, which range from three to 25 years.

The Company determines if an arrangement is representative of a lease at contract inception. Right-of-use (“ROU”) assets represent our right to use the underlying assets for the lease term and the corresponding lease liabilities represent our obligations to make lease payments arising from the leases. Operating and finance lease ROU assets and liabilities are recognized at the lease commencement date based on the present value of the lease payments over the lease term. When evaluating a contract, the Company applies certain judgments to determine, among other factors, lease classification as either operating or financing, lease term, and discount rate. The terms of certain of our leases include options to extend or terminate the lease, only when we can ascertain that it is reasonably certain we will exercise that option, as well as evergreen periods for which the penalties associated with termination are considered to be significant. Leases with an initial term of one year or less are not recorded on the balance sheets. As the Company does not have any leases with an implicit interest rate that can be readily determined, we utilize our incremental borrowing rate based on information available at the lease commencement date in determining the present value of lease payments. We determine our incremental borrowing rate at the lease commencement date using our Credit Facility benchmark rate and make adjustments for facility utilization and lease term. Subsequent measurement, as well as presentation of expenses and cash flows, will depend upon the classification of the lease as either a finance or operating lease. Please refer to Note 3 - Leases for additional discussion.

The Company periodically purchases carbon offsets and renewable energy credits as a means to offset carbon emissions generated by its operations that could not otherwise be reduced or eliminated. Commensurate with their use, purchased carbon offsets and renewable energy credits are initially capitalized at cost as an intangible asset within other noncurrent assets on the accompanying balance sheets. Subsequently, capitalized carbon offsets and renewable energy credits are expensed when applied to the Company's carbon emissions through depletion, depreciation, and amortization expense on the accompanying statements of operations. Purchased carbon offsets and renewable energy credits expected to be utilized within the next 12 months are presented as short-term within prepaid expenses and other on the accompanying balance sheets.

Deferred financing costs include origination, legal, and other fees incurred to issue debt or amend existing credit facilities. Deferred financing costs related to the Credit Facility are capitalized to prepaid expenses and other and other noncurrent assets on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations on a straight-line basis over the life of the Credit Facility. Deferred financing costs related to senior notes are capitalized within senior notes on the accompanying balance sheets and amortized to interest expense, net on the accompanying statements of operations using the effective interest method over the life of the respective borrowings.

The Company recognizes an asset retirement obligation at fair value based on the present value of costs expected to be incurred in connection with the future abandonment of its oil and natural gas properties, including wells and facilities, in accordance with applicable regulatory requirements. This obligation, and the corresponding capitalized cost recorded to proved properties, is recorded at the time assets are acquired, a well is completed and begins production, or a facility is constructed. The Company recognizes a periodic expense in connection with the accretion of the discounted asset retirement obligation over the remaining estimated economic lives of the respective long-lived assets. The accretion expense is recorded as a component of depreciation, depletion, and amortization in our accompanying statements of operations. If the fair value of the estimated asset retirement obligation changes, an adjustment is recorded to both the asset retirement obligation and the corresponding capitalized cost recorded to proved properties.

The Company periodically enters into commodity price derivative instruments to mitigate a portion of its exposure to potentially adverse market changes in commodity prices for its expected future oil, natural gas, and NGL production and the associated impact on cash flows. These instruments typically include commodity price swaps and collars, as well as, basis differential and roll differential swaps. The oil instruments are indexed to NYMEX WTI prices, natural gas instruments are indexed to NYMEX HH and CIG prices, and NGL instruments are indexed to OPIS prices, all of which have a high degree of historical correlation with actual prices received by the Company, before differentials.

Presently, our derivative contracts have been executed with 10 counterparties, all but one of which are members of our Credit Facility syndicate. We enter into contracts with counterparties whom we believe are well capitalized and have certain minimum investment grade senior unsecured debt ratings. However, if our counterparties fail to perform their obligations under the contracts, we could suffer financial loss.

Commodity price derivative instruments are measured at fair value and are included in the accompanying balance sheets as derivative assets and liabilities, with the exception of derivative instruments that meet the “normal purchase normal sale” exclusion. All commodity price derivative instruments are entered into for other-than-trading purposes. The Company does not designate its commodity price derivative contracts as hedging instruments. Accordingly, the Company reflects changes in the fair value of its commodity price derivative instruments in its accompanying statements of operations as they occur. We measure the fair value of our commodity price derivative instruments based upon a pricing model that utilizes market-based inputs, including, but not limited to, contractual price of the underlying position, current market prices, crude oil and natural gas forward curves, discount rates, volatility factors, and nonperformance risk.

As of December 31, 2021 and 2020, all derivative instruments held by the Company were subject to master netting arrangements with various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between it and the counterparty, at the election of both parties, for transactions that settle on the same date and in the same currency. The Company’s agreements also provide that in the event of an early termination, the counterparties have the right to offset amounts owed or owing under that and any other agreement with the same counterparty. The Company’s accounting policy is to not offset these positions in its accompanying balance sheets.

Revenue is recognized at the point in time when control of produced oil, natural gas, or NGL volumes transfer to the purchaser, which may differ depending on the applicable contractual terms. We consider the transfer of control to have occurred when the purchaser has the ability to direct the use of, and obtain substantially all of the remaining benefits from, the oil, natural gas, or NGL production.

Oil sales. Under the Company’s crude purchase and marketing contracts, the Company typically delivers production at the wellhead, or other contractually agreed-upon delivery points, and collects an agreed-upon index price, net of pricing differentials. In this scenario, the Company recognizes revenue when control of its oil production transfers to the purchaser at the wellhead, or other contractually agreed-upon delivery point, at the net contracted price received.

Natural gas and NGL sales. Under the Company's natural gas processing contracts, the Company delivers natural gas to a midstream processing entity at the wellhead, inlet of the midstream processing entity’s system, or other contractually agreed-upon delivery points. The delivery points are specified within each contract, and the point at which control transfers varies between the inlet and tailgate of the midstream processing facility. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sales of NGLs and residue gas.

For the contracts where the Company maintains control through the tailgate of the midstream processing facility, the Company recognizes revenue on a gross basis, with gathering, transportation, and processing fees presented as an expense in the accompanying statements of operations. Alternatively, for those contracts where the Company relinquishes control at the inlet of the midstream processing facility, the Company recognizes natural gas and NGL revenues based on the contracted amount of the proceeds received from the midstream processing entity and, as a result, the Company recognizes revenue on a net basis.

In certain natural gas processing agreements, the Company may elect to take its residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. Through the marketing process, the Company delivers product to the third-party purchaser at a contractually agreed-upon delivery point and receives a specified index price from the third-party purchaser. In this scenario, the Company recognizes revenue when the control transfers to the third-party purchaser at the delivery point based on the index price received from the third-party purchaser. The gathering and processing expense attributable to the natural gas processing contracts, as well as any transportation expense incurred to deliver the product to the third-party purchaser, are presented as gathering, transportation, and processing expense in the consolidated statements of operations.

As noted above, the Company records revenue in the month production is delivered and control is transferred to the purchaser. However, settlement statements and payment may not be received for 30 to 60 days after the date production is delivered and control is transferred. As a result, Company records a revenue accrual based on an estimate of the volumes delivered at estimated prices as determined by the applicable marketing agreements. The Company estimates its sales volumes based on Company-measured volume readings.

The Company records the differences between its estimates and the actual amounts received for product sales in the month in which payment is received from the purchaser. For the year ended December 31, 2021, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was insignificant. At December 31, 2021 and 2020, the Company's receivables from contracts with customers were $362.3 million and $32.7 million, respectively.

As further described in Note 6 - Commitments and Contingencies, two contracts have an additional aspect of variable consideration related to the minimum volume commitments (“MVCs”) as specified in the agreement. On an on-going basis, the Company performs an analysis of expected risk adjusted production applicable to the agreements based on approved production plans to determine if liquidated damages are probable. As of December 31, 2021, the Company believes that the volumes delivered will be in excess of the MVCs required then and for the upcoming approved production plan. As a result of this analysis, to date, no variable consideration related to potential liquidated damages has been considered in the transaction price for the related agreements.

The Company recognizes stock-based compensation based on the grant-date fair value of the equity instruments awarded. Stock-based compensation expense is recognized in the financial statements on a straight-line basis over the requisite service period for the entire award. The Company accounts for forfeitures of stock-based compensation awards as they occur. Please refer to Note 7 - Stock-Based Compensation for additional discussion.

The Company accounts for income taxes under the asset and liability method, which requires recognition of deferred tax assets and liabilities for the expected future tax consequences of events that have been included in the balance sheet or tax returns. Deferred income tax assets and liabilities are measured using enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. If we determine that it is more likely than not that some portion or all of the deferred income tax assets will not be realized, a valuation allowance is recorded, thereby reducing the deferred income tax assets to what is considered to be realizable.

The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained on examination by the taxing authorities based on the technical merits of the position. The Company's policy is to recognize interest and penalties related to uncertain tax positions in income tax expense. There were no uncertain tax positions during any period presented.

From time to time, we enter into acreage exchanges in order to consolidate our core acreage positions, enabling us to have more control over the timing of development activities, achieve higher working interests and provide us the ability to drill longer lateral length wells within those core areas. We account for our nonmonetary acreage exchanges in accordance with the guidance prescribed by Accounting Standards Codification (“ASC”) 845, Nonmonetary Transactions. For those exchanges that lack commercial substance, we record the acreage received at the net carrying value of the acreage surrendered to obtain it. For those acreage exchanges that are deemed to have commercial substance, we record the acreage received at fair value, with a related gain or loss recognized in earnings, in accordance with ASC 820, Fair Value Measurement. During the year ended December 31, 2021, the Company completed non-monetary acreage trades of certain oil and gas properties properties located in Weld County, Colorado. These trades were recorded at carryover basis with no gain or loss recognized.

As part of our business strategy, we regularly pursue the acquisition of oil and natural gas properties. We utilize the acquisition method to account for acquisitions of businesses. Pursuant to this method, we allocate the cost of the acquisition, or purchase price, to assets acquired and liabilities assumed based on fair values as of the acquisition date. Please refer to Note 2 - Acquisitions and Divestitures for additional discussion.

Company's commodity price derivative instruments are recorded at fair value. The Company’s Senior Notes, as defined in Note 5 – Long-Term Debt, are recorded at cost, net of any unamortized deferred financing costs, and their respective fair values are disclosed in Note 8 – Fair Value Measurements. The recorded value of the Company’s Credit Facility approximates its fair value as it bears interest at a floating rate that approximates a current market rate. The Company’s warrants were recorded at fair value upon issuance, with no recurring fair value measurement required.

In June 2016, the FASB issued Update No. 2016-13, Financial Instruments - Credit Losses (Topic 326): Measurement of Credit Losses on Financial Instruments. The update changes the impairment model for most financial assets and certain other instruments, including trade and other receivables, and requires entities to use a new forward-looking expected loss model that will result in the earlier recognition of allowances for losses. The amended standard was adopted using a modified retrospective approach on January 1, 2020. The Company considered past events (including historical experience), current economic and industry conditions, reasonable and supportable forecasts, and lives of receivable balances and loss experience. Historically and currently, the Company's credit losses on oil and natural gas sales receivables and joint interest receivables have not been significant, and the adoption of this standard did not have a material impact on its consolidated financial statements. As of December 31, 2021 and 2020 the Company had an allowance of $3.7 million and $0.4 million, respectively, established against joint interest receivables.

In August 2018, the FASB issued Update No. 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. The new standard was adopted on January 1, 2020. The standard only impacted the form of the Company's disclosures.

In March 2020, the FASB issued Update No. 2020-04, Reference Rate Reform (Topic 848), which provides temporary optional guidance to companies impacted by the transition away from the LIBOR. The amendment provides certain expedients and exceptions to applying GAAP in order to lessen the potential accounting burden when contracts, hedging relationships, and other transactions that reference LIBOR as a benchmark rate are modified. Further, in January 2021, the FASB issued Update No. 2021-01, Reference Rate Reform (Topic 848), which clarifies the scope of Topic 848 so that derivatives affected by the discounting transition are explicitly eligible for certain optional expedients and exceptions in Topic 848. These amendments are effective upon issuance and expire on December 31, 2022. The Company is currently assessing the impact of the LIBOR transition on the Company's consolidated financial statements.