PDC Energy (PDCE) 8-K Other Events

Exhibit 99.1

SRC Energy Inc. and Subsidiaries

Financial Statements as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019

SRC ENERGY INC. AND SUBSIDIARIES

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS

Index to Consolidated Financial Statements as of December 31, 2019 and 2018 and for each of the three years in the period ended December 31, 2019	1
Independent Auditors' Report	2
Consolidated Balance Sheets	4
Consolidated Statements of Operations	5
Consolidated Statements of Changes in Shareholders’ Equity	6
Consolidated Statements of Cash Flows	7
Notes to Consolidated Financial Statements	8

1

INDEPENDENT AUDITORS’ REPORT

To SRC Energy Inc.

We have audited the accompanying consolidated financial statements of SRC Energy Inc. and its subsidiaries (the "Company"), which comprise the consolidated balance sheets as of December 31, 2019 and 2018, and the related consolidated statements of operations, changes in shareholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes to the consolidated financial statements.

Management's Responsibility for the Consolidated Financial Statements

Management is responsible for the preparation and fair presentation of these consolidated financial statements in accordance with accounting principles generally accepted in the United States of America; this includes the design, implementation, and maintenance of internal control relevant to the preparation and fair presentation of consolidated financial statements that are free from material misstatement, whether due to fraud or error.

Auditors' Responsibility

Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We conducted our audits in accordance with auditing standards generally accepted in the United States of America. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free from material misstatement.

An audit involves performing procedures to obtain audit evidence about the amounts and disclosures in the consolidated financial statements. The procedures selected depend on the auditor’s judgment, including the assessment of the risks of material misstatement of the consolidated financial statements, whether due to fraud or error. In making those risk assessments, the auditor considers internal control relevant to the Company's preparation and fair presentation of the consolidated financial statements in order to design audit procedures that are appropriate in the circumstances, but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control. Accordingly, we express no such opinion. An audit also includes evaluating the appropriateness of accounting policies used and the reasonableness of significant accounting estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements.

We believe that the audit evidence we have obtained is sufficient and appropriate to provide a basis for our audit opinion.

Opinion

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of SRC Energy Inc. and its subsidiaries as of December 31, 2019 and 2018, and the results of their operations and their cash flows for each of the three years in the period ended December 31, 2019 in accordance with accounting principles generally accepted in the United States of America.

2

Disclaimer of Opinion on Supplementary Information

Our audits were conducted for the purpose of forming an opinion on the financial statements as a whole. The supplementary oil and natural gas producing information in Note 18 to the consolidated financial statements is presented for the purpose of additional analysis and is not a required part of the financial statements. This supplementary information is the responsibility of the Company’s management. Such information has not been subjected to the auditing procedures applied in our audits of the financial statements and, accordingly it is inappropriate to and we do not express an opinion on the supplementary information referred to above.

/s/ DELOITTE & TOUCHE LLP

February 26, 2020

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SRC ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED BALANCE SHEETS

(in thousands, except share data) 

ASSETS	December 31, 2019		December 31, 2018
Current assets:
Cash and cash equivalents	$	65,641	$	49,609
Accounts receivable:
Oil, natural gas, and NGL sales	76,807		100,973
Trade	23,826		39,415
Commodity derivative assets	—		34,906
Other current assets	14,993		7,537
Total current assets	181,267		232,440
Property and equipment:
Oil and gas properties, full cost method:
Proved properties, net of accumulated depletion	1,829,880		1,545,445
Wells in progress	224,052		227,262
Unproved properties and land, not subject to depletion	673,615		740,453
Oil and gas properties, net	2,727,547		2,513,160
Other property and equipment, net	3,903		5,540
Total property and equipment, net	2,731,450		2,518,700
Other assets	9,046		3,574
Total assets	$	2,921,763	$	2,754,714
LIABILITIES AND SHAREHOLDERS' EQUITY
Current liabilities:
Accounts payable and accrued expenses	$	98,126	$	150,010
Revenue payable	98,780		97,030
Production taxes payable	100,346		95,099
Asset retirement obligations	8,394		11,694
Commodity derivative liabilities	11,789		—
Total current liabilities	317,435		353,833
Revolving credit facility	165,000		195,000
Notes payable, net of issuance costs	540,615		539,360
Deferred taxes	94,613		37,967
Asset retirement obligations	46,288		40,052
Other liabilities	2,986		2,210
Total liabilities	1,166,937		1,168,422
Commitments and contingencies (See Note 16)
Shareholders' equity:
Preferred stock - $0.01 par value, 10,000,000 shares authorized: no shares issued and outstanding	—		—
Common stock - $0.001 par value, 400,000,000 shares authorized: 243,684,103 and 242,608,284 shares issued and outstanding as of December 31, 2019 and 2018, respectively	244		243
Additional paid-in capital	1,507,256		1,492,107
Retained earnings	247,326		93,942
Total shareholders' equity	1,754,826		1,586,292
Total liabilities and shareholders' equity	$	2,921,763	$	2,754,714

The accompanying notes are an integral part of these consolidated financial statements

4

SRC ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF OPERATIONS

(in thousands, except share and per share data)

	Year Ended December 31,
	2019			2018		2017
Oil, natural gas, and NGL revenues	$	635,502		$	645,641	$	362,516
Expenses:
Lease operating expenses	58,384			43,291		19,496
Transportation and gathering	16,794			9,135		3,226
Production taxes	34,112			59,830		36,266
Depreciation, depletion, and accretion	240,157			179,773		112,309
Goodwill impairment	—			40,711		—
Unused commitment charge	—			—		669
General and administrative	46,292			38,618		32,965
Total expenses	395,739			371,358		204,931
Operating income	239,763			274,283		157,585
Other income (expense):
Commodity derivative gain (loss)	(30,227		)	23,413		(4,226		)
Interest expense, net of amounts capitalized	—			—		(11,842		)
Interest income	314			99		363
Other income	180			194		503
Total other income (expense)	(29,733		)	23,706		(15,202		)
Income before income taxes	210,030			297,989		142,383
Income tax expense (benefit)	56,646			37,967		(99		)
Net income	$	153,384		$	260,022	$	142,482

The accompanying notes are an integral part of these consolidated financial statements

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SRC ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

(in thousands, except share data)

	Number of Common Shares	Par Value Common Stock		Additional Paid-In Capital			Retained Earnings (Deficit)			Total Shareholders' Equity
Balance, January 1, 2017	200,647,572	$	201	$	1,148,998		$	(308,460	)	$	840,739
Shares issued in equity offering	40,250,000	40		312,131			—			312,171
Shares issued under stock bonus and equity incentive plans	280,284	—		4,976			—			4,976
Shares issued for exercise of stock options	187,666	—		740			—			740
Stock-based compensation for options	—	—		5,076			—			5,076
Stock-based compensation for performance-vested stock units	—	—		2,938			—			2,938
Payment of tax withholdings using withheld shares	—	—		(688		)	—			(688		)
Other activity	—	—		102			(102		)	—
Net income	—	—		—			142,482			142,482
Balance, December 31, 2017	241,365,522	241		1,474,273			(166,080		)	1,308,434
Shares issued under stock bonus and equity incentive plans	432,700	1		5,972			—			5,973
Shares issued for exercise of stock options	810,062	1		4,301			—			4,302
Stock-based compensation for options	—	—		4,543			—			4,543
Stock-based compensation for performance-vested stock units	—	—		4,212			—			4,212
Payment of tax withholdings using withheld shares	—	—		(1,121		)	—			(1,121		)
Other activity		—		(73		)	—			(73		)
Net income	—	—		—			260,022			260,022
Balance, December 31, 2018	242,608,284	243		1,492,107			93,942			1,586,292
Shares issued under stock bonus and equity incentive plans	1,075,819	1		8,524			—			8,525
Stock-based compensation for options	—	—		2,949			—			2,949
Stock-based compensation for performance-vested stock units	—	—		4,873			—			4,873
Payment of tax withholdings using withheld shares	—	—		(1,197		)	—			(1,197		)
Net income	—	—		—			153,384			153,384
Balance, December 31, 2019	243,684,103	$	244	$	1,507,256		$	247,326		$	1,754,826

The accompanying notes are an integral part of these consolidated financial statements

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SRC ENERGY INC. AND SUBSIDIARIES

CONSOLIDATED STATEMENTS OF CASH FLOWS

(in thousands)

	Year Ended December 31,
	2019			2018			2017
Cash flows from operating activities:
Net income	$	153,384		$	260,022		$	142,482
Adjustments to reconcile net income to net cash provided by operating activities:
Depletion, depreciation, and accretion	240,157			179,773			112,309
Goodwill impairment	—			40,711			—
Settlements of asset retirement obligations	(10,938		)	(6,388		)	(4,541		)
Loss on extinguishment of debt	—			—			11,842
Provision for deferred taxes	56,646			37,967			—
Stock-based compensation expense	13,043			12,287			11,225
Mark-to-market of commodity derivative contracts:
Total loss (gain) on commodity derivative contracts	30,227			(23,413		)	4,226
Cash settlements on commodity derivative contracts	17,402			(19,359		)	942
Cash premiums paid for commodity derivative contracts	(1,971		)	—			—
Changes in operating assets and liabilities	40,722			39,543			12,830
Net cash provided by operating activities	538,672			521,143			291,315
Cash flows from investing activities:
Acquisitions of oil and gas properties and leaseholds	(5,255		)	(149,658		)	(661,468		)
Capital expenditures for drilling and completion activities	(441,934		)	(516,480		)	(450,384		)
Other capital expenditures	(56,380		)	(47,916		)	(17,841		)
Acquisition of land and other property and equipment	(368		)	(3,039		)	(4,186		)
Proceeds from sales of oil and gas properties and other	13,071			1,627			93,573
Net cash used in investing activities	(490,866		)	(715,466		)	(1,040,306		)
Cash flows from financing activities:
Proceeds from the sale of stock	—			—			322,000
Offering costs	—			(157		)	(9,745		)
Proceeds from the employee exercise of stock options	—			4,302			741
Payment of employee payroll taxes in connection with shares withheld	(1,197		)	(1,121		)	(688		)
Proceeds from revolving credit facility	—			195,000			250,000
Principal repayments on revolving credit facility	(30,000		)	—			(250,000		)
Proceeds from issuance of notes payable	—			—			550,000
Repayment of notes payable	—			—			(88,234		)
Financing fees on issuance of notes payable and amendments to revolving credit facility	(379		)	(2,588		)	(13,145		)
Finance lease payments	(198		)	(276		)	—
Net cash provided by (used in) financing activities	(31,774		)	195,160			760,929
Net increase in cash, cash equivalents, and restricted cash	16,032			837			11,938
Cash, cash equivalents, and restricted cash at beginning of period	49,609			48,772			36,834
Cash, cash equivalents, and restricted cash at end of period	$	65,641		$	49,609		$	48,772

Supplemental Cash Flow Information (See Note 17)

The accompanying notes are an integral part of these consolidated financial statements

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SRC ENERGY INC. AND SUBSIDIARIES

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

December 31, 2019, 2018, and 2017

1. Organization and Summary of Significant Accounting Policies

Organization:  SRC Energy Inc. (the "Company" or "SRC") is an independent oil and natural gas company engaged in the acquisition, exploration, development, and production of oil, natural gas, and NGLs, primarily in the D-J Basin of Colorado.

Basis of Presentation:  The consolidated financial statements include the accounts of the Company, including its wholly-owned subsidiaries. All significant intercompany balances and transactions have been eliminated in consolidation.  The Company prepares its consolidated financial statements in accordance with accounting principles generally accepted in the United States of America ("US GAAP").

Merger: On August 25, 2019, the Company entered into an Agreement and Plan of Merger ("PDC Merger Agreement") with PDC Energy, Inc., a Delaware corporation ("PDC"). On January 14, 2020, SRC merged with and into PDC, with PDC continuing as the surviving corporation (the “PDC Merger”). Pursuant to the PDC Merger Agreement, at the effective time of the PDC Merger, the Company's shareholders received 0.158 of a share of PDC common stock for each outstanding share of the Company's common stock, plus cash in lieu of any fractional PDC shares that otherwise would have been issued (the "Merger Consideration"). The PDC Merger Agreement also addresses the treatment of SRC equity awards in the PDC Merger. PDC’s common stock is listed and traded on the NASDAQ Global Select Market under the symbol PDCE. For the year ended December 31, 2019, the Company has incurred $8.7 million of merger transaction costs recognized in general and administrative expense of the consolidated statements of operations.

Use of Estimates:The preparation of consolidated financial statements in conformity with US GAAP requires management to make estimates and assumptions that affect the reported amount of assets and liabilities, including oil and natural gas reserves, production tax expenses, derivatives, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting period. Management routinely makes judgments and estimates about the effects of matters that are inherently uncertain. Management bases its estimates and judgments on historical experience and on various other factors that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Estimates and assumptions are revised periodically, and the effects of revisions are reflected in the consolidated financial statements in the period that it is determined to be necessary. Actual results could differ from these estimates.

Cash and Cash Equivalents:  The Company considers cash in banks, deposits in transit, and highly liquid debt instruments purchased with original maturities of less than three months to be cash and cash equivalents.

Oil and Gas Properties:    The Company uses the full cost method of accounting for costs related to its oil and gas properties. Accordingly, all costs associated with acquisition, exploration, and development of oil and natural gas reserves (including the costs of unsuccessful efforts) are capitalized into a single full cost pool. These costs include lease acquisition costs, geological and geophysical expenses, carrying charges on non-producing properties, costs of drilling, and overhead charges directly related to acquisition, exploration, and development activities. Under the full cost method, no gain or loss is recognized upon the sale or retirement of oil and gas properties unless non-recognition of such gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves.

Capitalized costs of oil and gas properties are depleted using the unit-of-production method based upon estimates of proved reserves. For depletion purposes, the volume of proved oil and natural gas reserves and production is converted into a common unit of measure at the energy equivalent conversion rate of six thousand cubic feet of natural gas to one barrel of oil. Investments in unproved properties and major development projects are not amortized until proved reserves associated with the projects can be determined or until impairment occurs. If the results of an assessment indicate that the properties are impaired, the amount of the impairment is added to the capitalized costs to be amortized.

Under the full cost method of accounting, a ceiling test is performed each quarter.  The full cost ceiling test is the impairment test prescribed by regulations of the Securities and Exchange Commission ("SEC").  The ceiling test determines a limit on the net book value of oil and gas properties. The ceiling is calculated as the sum of the present value of estimated future net revenues from proved oil and natural gas reserves, plus the cost of properties not being amortized, plus the lower of cost or estimated fair value of unproved properties included in the costs being amortized, less the income tax effects related to differences between the book and tax basis of the properties.  The present value of estimated future net revenues is computed by applying prices of oil and natural gas reserves to estimated future production of proved oil and natural gas reserves, less estimated future expenditures to be

8

incurred in developing and producing the proved reserves; the result is discounted at 10% and assumes continuation of current economic conditions. Future cash outflows associated with settling accrued asset retirement obligations that have been accrued in the balance are excluded from the calculation of the present value of future net revenues. The calculation of income tax effects takes into account the tax basis of oil and gas properties, net operating loss carryforwards, and the impact of statutory depletion. If the capitalized costs of proved and unproved oil and gas properties, net of accumulated depletion and prior impairments, and the related deferred income taxes exceed the ceiling limit, the excess is charged to expense. Once impairment expense is recognized, it cannot be reversed in future periods, even if increasing prices raise the ceiling amount. During the years ended December 31, 2019, 2018, and 2017, the Company did not recognize any ceiling test impairments.

The oil and natural gas prices used to calculate the full cost ceiling limitation are based upon a 12-month rolling average, calculated as the unweighted arithmetic average of the first day of the month price for each month within the preceding 12-month period unless prices are defined by contractual arrangements.  Prices are adjusted for basis or location differentials and are held constant for the productive life of each well.

Oil and Natural Gas Reserves: Oil and natural gas reserves represent theoretical, estimated quantities of oil and natural gas which, using geological and engineering data, are estimated with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions. There are numerous uncertainties inherent in estimating oil and natural gas reserves and their values including many factors beyond the Company’s control. Accordingly, reserve estimates are different from the future quantities of oil and natural gas that are ultimately recovered and the corresponding lifting costs associated with the recovery of these reserves.

The determination of depletion expense, as well as the ceiling test calculation related to the recorded value of the Company’s oil and gas properties, is highly dependent on estimates of proved oil and natural gas reserves.

Capitalized Interest: The Company capitalizes interest on expenditures made in connection with acquisitions of mineral interests that are currently not subject to depletion and exploration and development projects that are in progress.  Interest is capitalized during the period that activities are in progress to bring the projects to their intended use.  See Note 10 for additional information.

Capitalized Overhead: A portion of the Company’s overhead expenses are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenses are capitalized in the full cost pool. See Note 2 for additional information.

Other Property and Equipment: Support equipment (including such items as vehicles, computer equipment, and software), office leasehold improvements, office furniture and equipment, and buildings are stated at historical cost. Expenditures for support equipment relating to new assets or improvements are capitalized, provided the expenditure extends the useful life of an asset or extends the asset’s functionality. Support equipment, office leasehold improvements, and office furniture and equipment are depreciated under the straight-line method using estimated useful lives ranging from three to five years. Buildings are also depreciated under the straight-line method using estimated useful lives of thirty-nine years. No depreciation is taken on assets classified as construction in progress until the asset is placed into service. Gains and losses are recorded upon retirement, sale, or disposal of assets. Maintenance and repair costs are recognized as period costs when incurred. The Company evaluates its other property and equipment for impairment when events or changes in circumstances indicate that the related carrying amount may not be recoverable. 

9

Accounts Payable and Accrued Expenses: Accounts payable and accrued expenses consist of the following (in thousands):

	As of December 31,
	2019		2018
Trade accounts payable	$	2,829	$	2,029
Accrued well costs	72,121		130,784
Accrued G&A	5,647		4,913
Accrued LOE	8,380		8,366
Accrued interest	3,822		3,574
Operating lease liability	4,881		—
Accrued other	446		344
	$	98,126	$	150,010

Revenue Payable: Revenue payable represents amounts collected from purchasers for oil and natural gas sales which are revenues due to other working or royalty interest owners. Generally, the Company is required to remit amounts due under these liabilities within 30 days of the end of the month in which the related proceeds from the production are received unless we are waiting for the other owners to confirm their ownership.

Asset Retirement Obligations: The Company’s activities are subject to various laws and regulations, including legal and contractual obligations to reclaim, remediate, or otherwise restore properties at the time the asset is permanently retired.  Calculation of an asset retirement obligation ("ARO") requires estimates about several future events, including the life of the asset, the costs to retire the asset, and inflation factors.  The ARO is initially estimated based upon discounted cash flows over the life of the asset and is accreted to full value over time using the Company’s credit-adjusted risk-free rate.  Estimates are periodically reviewed and adjusted to reflect changes.

The present value of a liability for the ARO is initially recorded when it is incurred if a reasonable estimate of fair value can be made.  When the ARO is initially recorded, the Company capitalizes the cost by increasing the carrying value of the related asset.  Asset retirement costs ("ARCs") related to wells are capitalized to the full cost pool and subject to depletion.  Over time, the liability increases for the change in its present value, while the net capitalized cost decreases over the useful life of the asset as depletion expense is recognized.  In addition, ARCs are included in the ceiling test calculation when assessing the full cost pool for impairment.

Goodwill: Goodwill represents the excess of the purchase price over the fair value of net identifiable assets acquired in a business combination.  Goodwill is not amortized and is tested for impairment annually or whenever other circumstances or events indicate that the carrying amount of goodwill may not be recoverable. Historically, we performed the annual impairment assessment as of October 1.

When evaluating goodwill for impairment, the Company may first perform an assessment of qualitative factors to determine if the fair value of the reporting unit is more-likely-than-not greater than its carrying amount. If, based on the review of the qualitative factors, the Company determines it is not more-likely-than-not that the fair value of a reporting unit is less than its carrying value, the required impairment test can be bypassed. If the Company does not perform a qualitative assessment or if the fair value of the reporting unit is not more-likely-than-not greater than its carrying value, the Company must calculate the estimated fair value of the reporting unit.  If the carrying value of the reporting unit exceeds the estimated fair value, the Company should recognize an impairment charge.  The amount of impairment for goodwill is measured as the amount by which the carrying amount of the reporting unit exceeds the reporting unit's fair value; however, the loss recognized should not exceed the total amount of goodwill.  For purposes of assessing goodwill, the Company only has one reporting unit.

In the prior year, the Company performed its annual goodwill impairment test as of October 1, 2018 and determined that no impairment had occurred. However, as a result of a sustained decrease in the price of our common stock during the fourth quarter of 2018 caused by a significant decline in oil prices over the same period, the Company performed another goodwill impairment test as of December 31, 2018. The impairment test performed by the Company indicated that the carrying value of its reporting unit exceeded its fair value and that an impairment loss should be recognized in an amount equal to that excess, limited to the total amount of goodwill allocated to the reporting unit. Based on these results, the Company recorded a non-cash impairment charge of $40.7 million, reducing the carrying value of goodwill to zero. The Company utilized a market approach

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in estimating the fair value of the reporting unit. The primary assumptions used in the Company's impairment evaluations are based on the best available market information at the time and contain considerable management judgments.

Oil, Natural Gas, and NGL Revenues: The Company derives revenue primarily from the sale of oil, natural gas, and NGLs produced on its properties.  Revenues from production on properties in which the Company shares an economic interest with other owners are recognized on the basis of the Company's pro-rata interest. Revenues are reported on a net revenue interest basis, which excludes revenues that are attributable to other parties' working or royalty interests.  Revenue is recorded and receivables are accrued in the month production is delivered to the purchaser, at which time ownership of the product is transferred to the purchaser.  Payment is generally received between thirty and ninety days after the date of production.  Provided that reasonable estimates can be made, revenue and receivables are accrued to recognize delivery of product to the purchaser. Differences between estimates and actual volumes and prices, if any, are adjusted upon final settlement.

Major Customers:    The Company sells production to a small number of customers as is customary in the industry. Customers representing 10% or more of its oil, natural gas, and NGL revenue ("major customers") for each of the periods presented are shown in the following table:

	Year Ended December 31,
	2019	2018	2017
Company A	28%	17%	*
Company B	19%	20%	24%
Company C	16%	22%	33%
Company D	11%	13%	17%
Company E	*	13%	*

* less than 10%

Based on the current demand for oil and natural gas, the availability of other buyers, the multiple contracts for sales of our products, and the Company having the option to sell to other buyers if conditions warrant, the Company believes that the loss of our existing customers or individual contracts would not have a material adverse effect on us. Our oil and natural gas production is a commodity with a readily available market, and we sell our products under many distinct contracts. In addition, there are several oil and natural gas purchasers and processors within our area of operations to whom our production could be sold.

Accounts receivable consist primarily of receivables from oil, natural gas, and NGL sales and amounts due from other working interest owners who are liable for their proportionate share of well costs. The Company typically has the right to withhold future revenue disbursements to recover outstanding joint interest billings on outstanding receivables from joint interest owners.

Customers with balances greater than 10% of total receivable balances as of each of the periods presented are shown in the following table (these companies do not necessarily correspond to those presented above):

	As of December 31,
	2019	2018
Company A	20%	12%
Company B	18%	15%
Company C	11%	12%
Company D	*	13%

* less than 10%

The Company operates exclusively within the United States of America, and except for cash and cash equivalents, all of the Company’s assets are employed in, and all of its revenues are derived from, the oil and gas industry.

Lease Operating Expenses:  Costs incurred to operate and maintain wells and related equipment and facilities are expensed as incurred.  Lease operating expenses (also referred to as production or lifting costs) include the costs of labor to operate the wells and related equipment and facilities, repairs and maintenance, materials, fuel consumed, supplies utilized in operating the wells and related equipment and facilities, property taxes, and insurance applicable to proved properties and wells and related equipment and facilities.

Stock-Based Compensation:  The Company recognizes all equity-based compensation as stock-based compensation

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expense based on the fair value of the compensation measured at the grant date. For stock options, fair value is calculated using the Black-Scholes-Merton option pricing model.  For stock bonus awards and restricted stock units, fair value is the closing stock price for the Company's common stock on the grant date. For performance-vested stock units, fair value is calculated using a Monte Carlo simulation.  Once a grant date has been established, the compensation is recognized over the remaining vesting period of the grant.  See Note 11 for additional information.

Income Tax:  Income taxes are computed using the asset and liability method.  Accordingly, deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the financial statement carrying amounts of existing assets and liabilities and their respective tax bases as well as the effect of net operating losses, tax credits, and tax credit carryforwards.  Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the year in which the differences are expected to be recovered or settled.  The effect on deferred tax assets and liabilities of a change in income tax rates is recognized in the results of operations in the period that includes the enactment date.

No significant uncertain tax positions were identified as of any date on or before December 31, 2019.  The Company’s policy is to recognize interest and penalties related to uncertain tax benefits in income tax expense.  As of December 31, 2019, the Company has not recognized any interest or penalties related to uncertain tax benefits. See Note 13 for further information.

Commodity Derivative Instruments: The Company has entered into commodity derivative instruments, primarily utilizing swaps, puts, or collars to reduce the effect of price changes on a portion of its future oil and natural gas production. The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets and liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Realized gains and losses resulting from the contract settlement of derivatives are recorded in the commodity derivative gain (loss) line in the consolidated statement of operations. The Company values its derivative instruments by obtaining independent market quotes as well as using industry standard models that consider various assumptions, including quoted forward prices for commodities, risk-free interest rates, and estimated volatility factors as well as other relevant economic measures. The discount rate used in the fair values of these instruments includes a measure of nonperformance risk by the counterparty or the Company, as appropriate. For additional discussion, refer to Note 8.

Transportation Commitment Charge: The Company has entered into several agreements that require us to deliver minimum amounts of oil to a third-party marketer and/or other counterparties that transport oil via pipelines. See Note 16 for additional information. Pursuant to these agreements, we must deliver specific amounts, either from our own production or from oil that we acquire. If we are unable to fulfill all of our contractual delivery obligations from our own production, we may be required to pay penalties or damages pursuant to these agreements, or we may have to purchase oil from third parties to fulfill our delivery obligations. When we incur penalties of this type, we recognize the expense as a transportation commitment charge in the consolidated statement of operations.

Recently Adopted Accounting Pronouncements:

In February 2016, the Financial Accounting Standards Board ("FASB") issued Accounting Standard Update ("ASU") No. 2016-02, Leases (Topic 842), followed by other related ASUs that provided targeted improvements and additional practical expedient options (collectively “ASC 842”). ASC 842 requires lessees to recognize right-of-use (“ROU”) assets and lease payment liabilities in the balance sheet for leases representing the Company’s right to use the underlying assets over the lease term. Each lease that is recognized in the balance sheet will be classified as either finance or operating, with such classification affecting the pattern and classification of expense recognition in the consolidated statements of operations and presentation within the statements of cash flows.

The Company adopted ASC 842 on January 1, 2019 using the modified retrospective method. The Company elected as part of its adoption to also use the optional transition methodology whereby previously reported periods continue to be reported in accordance with historical accounting guidance for leases that were in effect for those prior periods. Policy elections and practical expedients that the Company has implemented as part of adopting ASC 842 include (a) excluding from the balance sheet leases with terms that are less than or equal to one year, (b) for all existing asset classes that contain both lease and non-lease components, combining these components together and accounting for them as a single lease component, (c) the package of practical expedients, which among other things allows the Company to avoid reassessing contracts that commenced prior to adoption that were properly evaluated under legacy GAAP, and (d) excluding land easements, which were not accounted for under the previous leasing guidance, that existed or expired before adoption of ASC 842. ASC 842 does not apply to leases used in the exploration or use of minerals, oil, and natural gas.

The Company's adoption of ASC 842 resulted in an increase in other assets, accounts payable and accrued expenses, and other liabilities line items in the January 1, 2019 consolidated balance sheet as a result of the additional ROU assets and related

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lease liabilities. Upon adoption on January 1, 2019, the Company recognized approximately $2.4 million in ROU assets and $4.3 million in liabilities for its operating leases. There was no cumulative effect to retained earnings upon the adoption of this guidance. See Note 15 for the new disclosures required by ASC 842.

Recently Issued Accounting Pronouncements: There were various updates recently issued by the FASB, most of which represented technical corrections to the accounting literature or application to specific industries and are not expected to a have a material impact on our reported financial position, results of operations, or cash flows.

Change in estimate: Production taxes are comprised primarily of two elements: severance tax and ad valorem tax. During the year ended December 31, 2019, the Company reduced its estimate for 2018 severance taxes. When preparing the 2018 severance tax return, the credit for ad valorem taxes was greater than originally estimated, resulting in a reduction of 2018 severance taxes. Based on this analysis, the Company's prior year accrual was reduced, resulting in an approximate $7.9 million reduction to our production taxes, which increased our operating income for the year ended December 31, 2019 by a corresponding amount.

2. Property and Equipment

The capitalized costs related to the Company’s oil and gas producing activities were as follows (in thousands):

	As of December 31,
	2019			2018
Oil and gas properties, full cost method:
Costs of proved properties:
Producing and non-producing	$	2,905,625		$	2,385,958
Less, accumulated depletion and full cost ceiling impairments	(1,075,745		)	(840,513		)
Subtotal, proved properties, net	1,829,880			1,545,445
Costs of wells in progress	224,052			227,262
Costs of unproved properties and land, not subject to depletion:
Lease acquisition and other costs	664,220			731,058
Land	9,395			9,395
Subtotal, unproved properties and land	673,615			740,453
Costs of other property and equipment:
Other property and equipment	10,102			9,642
Less, accumulated depreciation	(6,199		)	(4,102		)
Subtotal, other property and equipment, net	3,903			5,540
Total property and equipment, net	$	2,731,450		$	2,518,700

The Company periodically reviews its oil and gas properties to determine if the carrying value of such assets exceeds estimated fair value. For proved producing and non-producing properties, the Company performs a ceiling test each quarter to determine whether there has been an impairment to its capitalized costs. During the years ended December 31, 2019, 2018, and 2017, the calculated value of the ceiling limitation exceeded the carrying value of our oil and gas properties subject to the test, and no impairments were necessary.

The costs of unproved properties are withheld from the depletion base until such time as the properties are either developed or impaired. Unproved properties are reviewed on an annual basis, or more frequently if necessary, for impairment and, if impaired, are reclassified to proved properties and included in the depletion base. During the years ended December 31, 2019 and 2017, these reviews indicated that the carrying values had not been impaired. Therefore, no impairment was necessary for the years end December 31, 2019 or 2017. However, during the year ended December 31, 2018, the Company recorded an impairment of $1.2 million to the carrying value of its unproved properties.

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Capitalized Overhead: A portion of the Company’s overhead expenditures are directly attributable to acquisition, exploration, and development activities.  Under the full cost method of accounting, these expenditures, in the amounts shown in the table below, were capitalized in the full cost pool (in thousands):

	Year Ended December 31,
	2019		2018		2017
Capitalized overhead	$	14,481	$	12,775	$	10,293

Costs Incurred:  Costs incurred in oil and gas property acquisition, exploration, and development activities for the periods presented were (in thousands):

	Year Ended December 31,
	2019		2018		2017
Acquisition of property:
Unproved	$	2,428	$	46,039	$	538,489
Proved	3,512		136,652		139,154
Exploration costs	—		—		—
Development costs	384,008		583,660		460,875
Other property and equipment and land	592		3,039		4,397
Capitalized interest, capitalized G&A, and other	72,713		57,039		26,677
Total costs incurred	$	463,253	$	826,429	$	1,169,592

Capitalized Costs Excluded from Depletion:  The following table summarizes costs related to unproved properties and development costs that have been excluded from amounts subject to depletion at December 31, 2019 (in thousands):

	Period Incurred
	Year Ended December 31,						Prior to January 1, 2017		Total as of December 31, 2019
	2019		2018		2017
Unproved leasehold acquisition costs	$	8,791	$	74,184	$	387,866	$	193,379	$	664,220
Unproved development costs	62,845		7,486		—		—		70,331
Total unevaluated costs	$	71,636	$	81,670	$	387,866	$	193,379	$	734,551

There were no individually significant properties or significant development projects included in the Company’s unproved property balance.  The Company regularly evaluates these costs to determine whether impairment has occurred or proved reserves have been established.  The majority of these costs are expected to be evaluated and included in the depletion base within four years.

3. Acquisitions

The Company seeks to acquire developed and undeveloped oil and gas properties in the core Wattenberg Field to provide additional mineral acres upon which the Company can drill wells and produce hydrocarbons.

In September 2018, the Company completed the purchase of operated vertical and horizontal wells in the Greeley-Crescent development area. This purchase was contemplated in November 2017 when we entered into a purchase and sale agreement pursuant to which we agreed to acquire a total of approximately 30,200 net acres in an area referred to as the Greeley-Crescent project in the Wattenberg Field ("GCII Acquisition"). The first closing for this agreement occurred in December 2017. The effective date for this second closing was September 1, 2018. The total purchase price for the second closing was $96.9 million, composed of cash of $64.2 million and assumed liabilities of $32.7 million. The assumed liabilities included $25.8 million for asset retirement obligations. The entire purchase price has been allocated to proved oil and gas properties.

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In August 2018, the Company completed the purchase of leasehold acreage and associated non-operated production for $37.2 million in cash and the assumption of certain liabilities for a total purchase price of $37.5 million. The acreage increased our working interest in existing operations and planned wells. The purchase price for the acquisition was allocated as $23.9 million to proved oil and gas properties and $13.6 million to unproved oil and gas properties.

All of these transactions were accounted for as asset acquisitions, which requires the acquired assets and liabilities to be recorded at cost on the acquisition date.

4. Depletion, depreciation, and accretion ("DD&A")

DD&A consisted of the following (in thousands):

	Year Ended December 31,
	2019		2018		2017
Depletion of oil and gas properties	$	234,459	$	175,441	$	109,287
Depreciation and accretion	5,698		4,332		3,022
Total DD&A Expense	$	240,157	$	179,773	$	112,309

Capitalized costs of proved oil and gas properties are depleted quarterly using the units-of-production method based on a depletion rate, which is calculated by comparing production volumes for the quarter to estimated total proved reserves at the beginning of the quarter. For the year ended December 31, 2019, production of 22,584 thousand barrels of oil equivalent ("MBOE") represented 7.1% of estimated total proved reverses. For the year ended December 31, 2018, production of 18,448 MBOE represented 5.7% of estimated total proved reserves. For the year ended December 31, 2017, production of 12,481 MBOE represented 5.2% of estimated total proved reserves. DD&A expense was $10.63 per barrel of oil equivalent ("BOE"), $9.74 per BOE, and $9.00 per BOE for the years ended December 31, 2019, 2018, and 2017, respectively.

5. Asset Retirement Obligations

Upon completion or acquisition of a well, the Company recognizes obligations for its oil and natural gas operations for anticipated costs to remove and dispose of surface equipment, plug and reclaim the wells, and restore the drilling site to its original use.  The estimated present value of such obligations is determined using several assumptions and judgments about the ultimate settlement amounts, inflation factors, credit-adjusted discount rates, timing of settlement, and changes in regulations.  Changes in estimates are reflected in the obligations as they occur.  If the fair value of a recorded asset retirement obligation changes, a revision is recorded to both the asset retirement obligation and the capitalized asset retirement cost.  The following table summarizes the changes in asset retirement obligations associated with the Company's oil and gas properties (in thousands):

	Year Ended December 31,
	2019			2018
Beginning asset retirement obligation	$	51,746		$	31,622
Obligations incurred with development activities	2,311			4,174
Obligations assumed with acquisitions	—			26,150
Accretion expense	3,472			2,310
Obligations discharged with asset retirements and divestitures	(11,712		)	(12,267		)
Revisions in previous estimates	8,865			(243		)
Ending asset retirement obligation	$	54,682		$	51,746
Less, current portion	(8,394		)	(11,694		)
Non-current portion	$	46,288		$	40,052

During the year ended December 31, 2019, the Company increased its asset retirement obligation by $8.9 million due primarily to a revision to the expected timing of the future cash flows.

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6. Revolving Credit Facility

On April 2, 2018, the Company entered into a second amended and restated credit agreement (the "Restated Credit Agreement") with certain banks and other lenders. The Restated Credit Agreement provides a revolving credit facility (sometimes referred to as the "Revolver") and a $25 million swingline facility with a maturity date of April 2, 2023. The Revolver is available for working capital for exploration and production operations, acquisitions of oil and gas properties, and general corporate purposes and to support letters of credit. At December 31, 2019, the terms of the Revolver provided for up to $1.5 billion in borrowings, an aggregate elected commitment of $550 million, and a borrowing base limitation of $650 million. As of December 31, 2019 and December 31, 2018, the outstanding principal balance was $165.0 million and $195.0 million, respectively. At December 31, 2019, the Company had $11.6 million letters of credit issued.

Interest under the Revolver accrues monthly at a variable rate.  For each borrowing, the Company designates its choice of reference rates, which can be either the Prime Rate plus a margin or LIBOR plus a margin. The interest rate margin, as well as other bank fees, varies with utilization of the Revolver. The average annual interest rate for borrowings during the year ended December 31, 2019 and 2018 was 4.3% and 4.2%, respectively.

Certain of the Company’s assets, including substantially all of its producing wells and developed oil and gas leases, have been designated as collateral under the Restated Credit Agreement. The amount available to be borrowed is subject to scheduled redeterminations on a semi-annual basis. If certain events occur or if the bank syndicate or the Company so elects in certain circumstances, an unscheduled redetermination could be undertaken. The lenders consented to a postponement of the redetermination scheduled for November 2019.

The Restated Credit Agreement contains covenants that, among other things, restrict the payment of dividends and limit our overall commodity derivative position to a maximum position that varies over 5 years as a percentage of the projected production from proved developed producing or total proved reserves as reflected in the most recently completed reserve report.

Furthermore, the Restated Credit Agreement requires the Company to maintain compliance with certain financial and liquidity ratio covenants. In particular, the Company must not (a) permit its ratio of total funded debt to EBITDAX, as defined in the agreement, to be greater than or equal to 4.0 to 1.0 as of the last day of any fiscal quarter or (b) permit its ratio of current assets to current liabilities, each as defined in the agreement, to be less than 1.0 to 1.0 as of the last day of any fiscal quarter. As of December 31, 2019, the most recent compliance date, the Company was in compliance with these loan covenants.

In connection with the completion of the PDC Merger on January 14, 2020, PDC terminated all commitments and repaid all amounts outstanding under the Restated Credit Agreement.

7. Notes Payable

In November 2017, the Company issued $550 million aggregate principal amount of 6.25% Senior Notes (the "2025 Senior Notes") in a private placement to qualified institutional buyers. The maturity for the payment of principal is December 1, 2025. Interest on the 2025 Senior Notes accrues at 6.25% and began accruing on November 29, 2017. Interest is payable on June 1 and December 1 of each year, beginning on June 1, 2018. The 2025 Senior Notes were issued pursuant to an indenture dated as of November 29, 2017 (the "Indenture") and are guaranteed on a senior unsecured basis by the Company’s existing and future subsidiaries that incur or guarantee certain indebtedness, including indebtedness under the Revolver. As of December 31, 2019, none of the Company's subsidiaries met the criteria outlined within the Indenture to be considered a guarantor of the 2025 Senior Notes. As of December 31, 2019, the most recent compliance date, the Company was in compliance with its loan covenants.

The net proceeds from the sale of the 2025 Senior Notes were $538.1 million after deductions of $11.9 million for expenses and underwriting discounts and commissions. The associated expenses and underwriting discounts and commissions are amortized using the interest method at an effective interest rate of 6.6%. The net proceeds were used to fund the GCII Acquisition as discussed further in Note 3, to repay our previously outstanding senior notes due 2021, and to pay off the then-outstanding Revolver balance.

In connection with the completion of the PDC Merger on January 14, 2020, PDC assumed all of the Company’s obligations under the 2025 Senior Notes. On January 17, 2020, PDC made an offer to repurchase the 2025 Senior Notes from the holders at 101% of the principal amount of the 2025 Senior Notes, together with any accrued and unpaid interest to the date of repurchase. Upon expiration of the repurchase offer on February 18, 2020, holders of $447.7 million of the outstanding 2025 Senior Notes accepted the redemption offer for a total redemption price of approximately $452.2 million, plus accrued and unpaid interest of $6.2 million. The repurchase was funded by proceeds from PDC's revolving credit facility.

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8. Commodity Derivative Instruments

The Company has entered into commodity derivative instruments, as described below. Our commodity derivative instruments may include but are not limited to "collars," "swaps," and "put" positions. Our derivative strategy, including the volumes and commodities covered and the relevant strike prices, is based in part on our view of expected future market conditions and our analysis of well-level economic return potential. In addition, our use of derivative contracts is subject to stipulations set forth in the Revolver.

A "put" option gives the owner the right, but not the obligation, to sell the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may at times purchase put options, which require us to pay premiums at the time we purchase the contracts. These premiums represent the fair value of the purchased put as of the date of purchase.

A "call" option gives the owner the right, but not the obligation, to purchase the underlying commodity at a specified price (strike price) within a specific time period. Depending on market conditions, strike prices, and the value of the contracts, we may, at times, sell call options in conjunction with the purchase of put options to create "collars." We regularly utilize "no premium" (a.k.a. zero cost) collars where the cost of the put is offset by the proceeds of the call. At settlement, we receive the difference between the published index price and a floor price if the index price is below the floor. We pay the difference between the ceiling price and the index price if the index price is above the contracted ceiling price. No amounts are paid or received if the index price is between the floor and the ceiling price.

Additionally, at times, we may enter into swaps. Swaps are derivative contracts which obligate two counterparties to effectively trade the underlying commodity at a set price or price differential over a specified term.

The Company may, from time to time, add incremental derivatives to cover additional production, restructure existing derivative contracts, or enter into new transactions to modify the terms of current contracts in order to realize the current value of the Company’s existing positions. The Company does not enter into derivative contracts for speculative purposes.

In conjunction with certain derivative contracts, the Company deferred the payment of certain put premiums. The put premium liabilities become payable monthly as the hedge production month becomes the prompt production month. The Company amortizes the deferred put premium liabilities as they become payable. As of December 31, 2019, the Company had no outstanding put premium liabilities.

The use of derivatives involves the risk that the counterparties to such instruments will be unable to meet the financial terms of such contracts. The Company’s derivative contracts are currently with five counterparties. Each of the counterparties are lenders in the Revolver. The Company has netting arrangements with the counterparties that provide for the offset of payables against receivables from separate derivative arrangements with the counterparty in the event of contract termination. The derivative contracts may be terminated by a non-defaulting party in the event of default by one of the parties to the agreement.

The Company’s commodity derivative instruments are measured at fair value and are included in the accompanying consolidated balance sheets as commodity derivative assets or liabilities. Unrealized gains and losses are recorded based on the changes in the fair values of the derivative instruments. Both the unrealized and realized gains and losses are recorded in the consolidated statements of operations. The Company’s cash flow is only impacted when the actual settlements under commodity derivative contracts result in it making or receiving a payment to or from the counterparty. Actual cash settlements can occur at either the scheduled maturity date of the contract or at an earlier date if the contract is liquidated prior to its scheduled maturity. These settlements under the commodity derivative contracts are reflected as operating activities in the Company’s consolidated statements of cash flows.

The Company’s commodity derivative contracts as of December 31, 2019 are summarized below:

Settlement Period	Derivative Instrument	Volumes (Bbls per day)	Weighted-Average Fixed Price
Crude Oil - NYMEX WTI
Jan 1, 2020 - Dec 31, 2020	Swap	10,700	$	55.42

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Offsetting of Derivative Assets and Liabilities

As of December 31, 2019 and 2018, all derivative instruments held by the Company were subject to enforceable master netting arrangements held by various financial institutions. In general, the terms of the Company’s agreements provide for offsetting of amounts payable or receivable between the Company and the counterparty, at the election of either party, for transactions that occur on the same date and in the same currency. The Company’s agreements also provide that, in the event of an early termination, each party has 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 offset these positions in its consolidated balance sheets.

The following table provides a reconciliation between the net assets and liabilities reflected in the accompanying consolidated balance sheets and the potential effect of master netting arrangements on the fair value of the Company’s derivative contracts (in thousands):

		As of December 31, 2019
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet		Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	—	$	—	$	—
Commodity derivative contracts	Non-current assets	$	—	$	—	$	—
Commodity derivative contracts	Current liabilities	$	11,789	$	—	$	11,789
Commodity derivative contracts	Non-current liabilities	$	—	$	—	$	—

		As of December 31, 2018
Underlying Commodity	Balance Sheet Location	Gross Amounts of Recognized Assets and Liabilities		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets and Liabilities Presented in the Balance Sheet
Commodity derivative contracts	Current assets	$	39,485	$	(4,579	)	$	34,906
Commodity derivative contracts	Non-current assets	$	—	$	—		$	—
Commodity derivative contracts	Current liabilities	$	4,579	$	(4,579	)	$	—
Commodity derivative contracts	Non-current liabilities	$	—	$	—		$	—

The amount of gain (loss) recognized in the consolidated statements of operations related to derivative financial instruments was as follows (in thousands):

	Year Ended December 31,
	2019			2018			2017
Realized gain (loss) on commodity derivatives	$	16,468		$	(19,359	)	$	39
Unrealized gain (loss) on commodity derivatives	(46,695		)	42,772			(4,265		)
Total gain (loss)	$	(30,227	)	$	23,413		$	(4,226	)

Realized gains and losses represent the monthly settlement of derivative contracts at their scheduled maturity date, net of the premiums attributable to settled commodity contracts. The following table summarizes derivative realized gains and losses during the periods presented (in thousands):

	Year Ended December 31,
	2019			2018			2017
Monthly settlements	$	18,439		$	(19,359	)	$	1,062
Premiums attributable to settled commodity contracts	(1,971		)	—			(1,023		)
Total realized gain (loss)	$	16,468		$	(19,359	)	$	39

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Credit Related Contingent Features

As of December 31, 2019, all counterparties to the Company's derivative instruments were members of the Company’s credit facility syndicate. The Company’s obligations under the credit facility and its derivative contracts are secured by liens on substantially all of the Company’s producing oil and gas properties.

9. Fair Value Measurements

ASC 820, Fair Value Measurements and Disclosure, establishes a hierarchy for inputs used in measuring fair value for financial assets and liabilities that maximizes the use of observable inputs and minimizes the use of unobservable inputs by requiring that the most observable inputs be used when available.  Observable inputs are inputs that market participants would use in pricing the asset or liability based on market data obtained from sources independent of the Company.  Unobservable inputs are inputs that reflect the Company’s assumptions of what market participants would use in pricing the asset or liability based on the best information available in the circumstances.  The hierarchy is broken down into three levels based on the reliability of the inputs as follows:

• Level 1: Quoted prices available in active markets for identical assets or liabilities;

• Level 2: Quoted prices in active markets for similar assets and liabilities that are observable for the asset or liability; and

• Level 3: Unobservable pricing inputs that are generally less observable from objective sources, such as discounted cash or valuation models.

The financial assets and liabilities are classified based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the valuation of the fair value of assets and liabilities and their placement within the fair value hierarchy levels.

The Company’s non-recurring fair value measurements include goodwill, unproved properties, asset retirement obligations, and purchase price allocations for the fair value of assets and liabilities acquired through business combinations and certain asset acquisitions. Refer to Notes 1, 3, and 5 for further discussion of goodwill, business combinations and asset acquisitions, and asset retirement obligations, respectively.

The Company determines the estimated fair value of its goodwill using a quoted market price for the Company as adjusted for a control premium. As the control premium is an unobservable pricing input, this input is deemed to be a Level 3 input. See Note 1 for additional information.

The acquisition of a group of assets in a business combination transaction and certain asset acquisitions requires fair value estimates for assets acquired and liabilities assumed.  The fair value of assets and liabilities acquired is calculated using a net discounted cash flow approach for the proved producing, proved undeveloped, probable, and possible properties. The discounted cash flows are developed using the income approach and are based on management’s expectations for the future.  Unobservable inputs include estimates of future oil and natural gas production from the Company’s reserve reports, commodity prices based on the NYMEX forward price curves as of the date of the estimate (adjusted for basis differentials), estimated operating and development costs, and a risk-adjusted discount rate (all of which are designated as Level 3 inputs within the fair value hierarchy). For unproved properties, the fair value is determined using market comparables.

The Company determines the estimated fair value of its asset retirement obligations by calculating the present value of estimated cash flows related to plugging and reclamation liabilities using Level 3 inputs. The significant inputs used to calculate such liabilities include estimates of costs to be incurred, the Company’s credit-adjusted risk-free rate, inflation rate, and estimated dates of retirement. The asset retirement liability is accreted to its present value each period, and the capitalized asset retirement cost is depleted as a component of the full cost pool using the units-of-production method. See Notes 3 and 5 for additional information.

The following table presents the Company’s financial assets and liabilities that were accounted for at fair value on a recurring basis by level within the fair value hierarchy (in thousands):

	Fair Value Measurements at December 31, 2019
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	—	$	—	$	—
Commodity derivative liability	$	—	$	11,789	$	—	$	11,789

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	Fair Value Measurements at December 31, 2018
	Level 1		Level 2		Level 3		Total
Financial assets and liabilities:
Commodity derivative asset	$	—	$	34,906	$	—	$	34,906
Commodity derivative liability	$	—	$	—	$	—	$	—

Commodity Derivative Instruments

The Company determines its estimate of the fair value of commodity derivative instruments using a market approach based on several factors, including quoted market prices in active markets, quotes from third parties, the credit rating of each counterparty, and the Company’s own credit standing. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparties to its derivative contracts would default by failing to make any contractually required payments. The Company considers the counterparties to be of substantial credit quality and believes that they have the financial resources and willingness to meet their potential repayment obligations associated with the derivative transactions. At December 31, 2019, derivative instruments utilized by the Company consist of swaps. The oil, natural gas, and propane derivative markets are highly active. Although the Company’s derivative instruments are based on several factors including public indices, the instruments themselves are traded with third-party counterparties. As such, the Company has classified these instruments as Level 2.

Fair Value of Financial Instruments

The Company’s financial instruments consist primarily of cash and cash equivalents, accounts receivable, accounts payable, commodity derivative instruments (discussed above), notes payable, and credit facility borrowings. The carrying values of cash and cash equivalents, cash held in escrow, accounts receivable, and accounts payable are representative of their fair values due to their short-term maturities. Due to the variable interest rate paid on the credit facility borrowings, the carrying value is representative of its fair value.

The fair value of the notes payable is estimated to be $555.8 million at December 31, 2019. The Company determined the fair value of its notes payable at December 31, 2019 by using observable market-based information for quoted prices of the debt instruments. The Company has classified the notes payable as Level 1.

10. Interest Expense

The components of interest expense are (in thousands):

	Year Ended December 31,
	2019			2018			2017
Revolving credit facility	$	7,744		$	2,209		$	2,004
Notes payable	34,375			34,375			10,036
Amortization of debt issuance costs and other	3,534			3,926			3,084
Debt extinguishment costs	—			—			11,842
Less: interest capitalized	(45,653		)	(40,510		)	(15,124		)
Interest expense, net	$	—		$	—		$	11,842

11. Equity and Stock-Based Compensation

Equity

At the 2018 annual meeting of shareholders of the Company held on May 18, 2018, the shareholders approved the Third Amended and Restated Articles of Incorporation of the Company to increase the number of authorized shares of common stock of the Company from 300,000,000 to 400,000,000.

On August 25, 2019, the Company entered into the PDC Merger Agreement with PDC. On January 14, 2020, the PDC Merger was completed. Pursuant to the PDC Merger Agreement, at the effective time of the PDC Merger, the Company's

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shareholders received 0.158 of a share of PDC common stock for each outstanding share of the Company's common stock, plus cash in lieu of any fractional PDC shares that otherwise would have been issued.

Stock-Based Compensation

In addition to cash compensation, the Company may compensate employees and directors with equity-based compensation in the form of stock options, performance-vested stock units, restricted stock units, stock bonus shares, and other equity awards. The Company records its equity compensation by pro-rating the estimated grant-date fair value of each grant over the period of time that the recipient is required to provide services to the Company (the "vesting period").  The calculation of fair value is based, either directly or indirectly, on the quoted market value of the Company’s common stock.  Indirect valuations are calculated using the Black-Scholes-Merton option pricing model or a Monte Carlo model. For the periods presented, all stock-based compensation was either classified as a component within general and administrative expense in the Company's consolidated statements of operations or, for that portion which is directly attributable to individuals performing acquisition, exploration, and development activities, was capitalized to the full cost pool. As of December 31, 2019, there were 10,500,000 common shares authorized for grant under the 2015 Equity Incentive Plan, of which 1,039,966 shares were available for future grants. The shares available for future grant exclude 1,508,273 shares which have been reserved for future vesting of performance-vested stock units in the event that these awards met the criterion to vest at their maximum multiplier.

At the effective time of the PDC Merger, (1) each outstanding SRC restricted stock unit and stock bonus award became fully vested and was cancelled in exchange for the Merger Consideration in respect of each share of SRC common stock underlying the applicable award, (2) each SRC performance stock unit that was outstanding became vested and was cancelled in exchange for the Merger Consideration in respect of each share of SRC common stock underlying the applicable award (with such number of shares of SRC common stock determined based on target performance and any remaining shares of SRC common stock subject to the award forfeited), less applicable tax withholdings, (3) each SRC performance stock unit granted following the execution of the PDC Merger Agreement as required by the terms of the PDC Merger Agreement (see below for further discussion) was assumed and converted into a PDC performance stock unit that remains subject to the same terms and conditions (including performance-vesting terms) that applied immediately prior to the effective time, except that the number of shares of PDC common stock subject to each PDC performance stock unit was determined by multiplying the number of shares subject to the SRC performance stock unit by 0.158 (rounded to the nearest whole share), (4) each outstanding in-the-money SRC stock option was cancelled in exchange for the Merger Consideration in respect of each “Net Share Option” subject to the applicable option and (5) each outstanding, out-of-the-money SRC stock option was cancelled for no consideration.

The amount of stock-based compensation was as follows (in thousands):

	Year Ended December 31,
	2019			2018			2017
Stock options	$	2,949		$	4,543		$	5,076
Performance-vested stock units	4,873			4,212			2,938
Restricted stock units and stock bonus shares	8,524			5,972			4,977
Total stock-based compensation	16,346			14,727			12,991
Less: stock-based compensation capitalized	(3,303		)	(2,440		)	(1,766		)
Total stock-based compensation expense	$	13,043		$	12,287		$	11,225

Stock options

No stock options were granted during the years ended December 31, 2019, 2018, and 2017.

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The following table summarizes activity for stock options for the periods presented:

	Number of Shares		Weighted-Average Exercise Price		Weighted-Average Remaining Contractual Life	Aggregate Intrinsic Value (thousands)
Outstanding, December 31, 2016	6,001,500		$	9.27	8.0 years	$	6,515
Granted	—		—
Exercised	(187,666	)	3.95			976
Expired	(41,000	)	11.98
Forfeited	(136,000	)	10.97
Outstanding, December 31, 2017	5,636,834		9.38		7.0 years	4,806
Granted	—		—
Exercised	(823,883	)	5.36			4,611
Expired	(37,400	)	11.22
Forfeited	(122,917	)	9.93
Outstanding, December 31, 2018	4,652,634		10.06		6.4 years	49
Granted	—		—
Exercised	—		—			—
Expired	(85,000	)	9.90
Forfeited	(58,800	)	8.28
Outstanding, December 31, 2019	4,508,834		$	10.09	5.1 years	$	28
Outstanding, Exercisable at December 31, 2019	4,110,834		$	10.23	5.0 years	$	28

The following table summarizes information about issued and outstanding stock options as of December 31, 2019:

	Outstanding Options				Exercisable Options
Range of Exercise Prices	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life	Options	Weighted-Average Exercise Price per Share		Weighted-Average Remaining Contractual Life
Under $5.00	35,000	$	3.31	2.5 years	35,000	$	3.31	2.5 years
$5.00 - $6.99	671,000	6.29		4.2 years	530,600	6.30		3.6 years
$7.00 - $10.99	1,323,334	9.42		5.1 years	1,146,134	9.44		4.9 years
$11.00 - $13.46	2,479,500	11.57		5.4 years	2,399,100	11.57		5.4 years
Total	4,508,834	$	10.09	5.1 years	4,110,834	$	10.23	5.0 years

The estimated unrecognized compensation cost from stock options not vested as of December 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	1,297
Remaining vesting period	1.0 years

At the effective time of the PDC Merger, 10,000 stock options were cancelled in exchange for the Merger Consideration and 4,473,834 stock options were cancelled for no consideration.

Restricted stock units and stock bonus awards

The Company grants restricted stock units and stock bonus awards to directors, eligible employees, and officers under its equity incentive plan.  Restrictions and vesting periods for the awards are determined by the Compensation Committee of the Board of Directors and are set forth in the award agreements. Each restricted stock unit or stock bonus award represents one share of the Company’s common stock to be released from restrictions upon completion of the vesting period. The awards typically

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vest in equal increments over three to five years. Restricted stock units and stock bonus awards are valued at the closing price of the Company’s common stock on the grant date and are recognized over the vesting period of the award.

The following table summarizes activity for restricted stock units and stock bonus awards for the periods presented:

	Number of Shares		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016	890,336		$	9.55
Granted	681,568		8.29
Vested	(455,772	)	9.21
Forfeited	(28,746	)	9.74
Not vested, December 31, 2017	1,087,386		8.89
Granted	1,130,388		7.76
Vested	(478,517	)	8.96
Forfeited	(99,339	)	9.28
Not vested, December 31, 2018	1,639,918		8.07
Granted	1,733,634		4.88
Vested	(876,142	)	8.01
Forfeited	(89,980	)	6.25
Not vested, December 31, 2019	2,407,430		$	5.86

The estimated unrecognized compensation cost from restricted stock units and stock bonus awards not vested as of December 31, 2019, which will be recognized ratably over the remaining vesting period, is as follows:

Unrecognized compensation (in thousands)	$	8,365
Remaining vesting period	1.8 years

At the effective time of the PDC Merger, 1,701,568 restricted stock units and stock bonus awards became fully vested and were cancelled in exchange for the Merger Consideration.

Performance-vested stock units

The Company grants two types of performance-vested stock units ("PSUs") to certain executives under its long-term incentive plan. The number of shares of the Company’s common stock that may be issued to settle PSUs ranges from zero to two times the number of PSUs awarded. The shares issued for PSUs are determined based on the Company’s performance over a three-year measurement period and vest in their entirety at the end of the measurement period. The PSUs will be settled in shares of the Company’s common stock following the end of the three-year performance cycle. Any PSUs that have not vested at the end of the applicable measurement period are forfeited.

Goal-Based PSUs - These PSUs are earned and vested after 2020 based on a discretionary assessment by the Compensation Committee. This assessment is anticipated to measure the performance of the Company and the executives over the defined vesting period. As vesting is based on the discretion of the Compensation Committee, we have not yet met the requirements of establishing an accounting grant date for them.  This will occur when the Compensation Committee determines and communicates the vesting percentage to the award recipients, which will then trigger the service inception date, the fair value of the awards, and the associated expense recognition period.  As of December 31, 2019, 274,898 Goal-Based PSUs remained outstanding.

Total Shareholder Return ("TSR") PSUs - The vesting criterion for the TSR PSUs is based on a comparison of the Company’s TSR for the measurement period compared with the TSRs of a group of peer companies for the same measurement period. As the vesting criterion is linked to the Company's share price, it is considered a market condition for purposes of calculating the grant-date fair value of the awards.

The fair value of the TSR PSUs was measured at the grant date with a stochastic process method using a Monte Carlo simulation. A stochastic process is a mathematically defined equation that can create a series of outcomes over time. These outcomes are not deterministic in nature, which means that by iterating the equations multiple times, different results will be

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obtained for those iterations. In the case of the Company’s TSR PSUs, the Company cannot predict with certainty the path its stock price or the stock prices of its peers will take over the performance period. By using a stochastic simulation, the Company can create multiple prospective stock pathways, statistically analyze these simulations, and ultimately make inferences regarding the most likely path the stock price will take. As such, because future stock prices are stochastic, or probabilistic with some direction in nature, the stochastic method, specifically the Monte Carlo Model, is deemed an appropriate method by which to determine the fair value of the TSR PSUs. Significant assumptions used in this simulation include the Company’s expected volatility, risk-free interest rate based on U.S. Treasury yield curve rates with maturities consistent with the measurement period, and the volatilities for each of the Company’s peers.

The assumptions used in valuing the TSR PSUs granted were as follows:

	Year Ended December 31,
	2019		2018		2017
Weighted-average expected term	2.9 years		2.8 years		2.9 years
Weighted-average expected volatility	48	%	52	%	59	%
Weighted-average risk-free rate	2.49	%	2.41	%	1.34	%

As of December 31, 2019, unrecognized compensation for TSR PSUs was $5.1 million and will be amortized through 2021. A summary of the status and activity of TSR PSUs is presented in the following table:

	Number of Units1		Weighted-Average Grant-Date Fair Value
Not vested, December 31, 2016	478,510		$	8.09
Granted	473,374		10.79
Vested	—		—
Forfeited	—		—
Not vested, December 31, 2017	951,884		9.44
Granted	321,507		13.11
Vested	(465,188	)	8.09
Forfeited	(28,175	)	10.15
Not vested, December 31, 2018	780,028		11.73
Granted	918,842		5.74
Vested	(465,495	)	10.79
Forfeited	—		—
Not vested, December 31, 2019	1,233,375		$	7.62

¹ The number of awards assumes that the associated vesting condition is met at the target amount. The final number of shares of the Company’s common stock issued may vary depending on the performance multiplier, which ranges from zero to two, depending on the level of satisfaction of the vesting condition.

On January 13, 2020, SRC granted 986,885 new TSR PSUs (“New PSU”) in respect of shares of SRC common stock, on the terms specified in the PDC Merger Agreement. The New PSU awards will be assumed or substituted by PDC and converted automatically into new performance stock unit awards of PDC, subject to the same terms and conditions as were applicable to the New PSU awards immediately prior to the effective time. The number of shares of PDC common stock covered by such assumed awards will be based on the target number of SRC shares covered by such awards multiplied by 0.158, the exchange ratio in the PDC Merger. The range of shares of PDC common stock that may be earned in respect of the New PSUs is 0% to 200% of the applicable target.

At the effective time of the PDC Merger, 1,508,273 performance stock units became vested and were cancelled in exchange for the Merger Consideration with such number of shares of common stock determined based on target performance and any remaining shares of common stock subject to the award forfeited. An additional 465,495 performance stock units that were vested in 2019 but were unsettled at the effective time of the PDC Merger were cancelled in exchange for the Merger Consideration with such number of shares of common stock determined based on target performance and any remaining shares of common stock subject to the award forfeited.

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12. Defined Contribution Plan

The Company sponsors a 401(k) defined contribution plan (the "plan") for eligible employees. Effective January 1, 2017, the Company modified the plan to include a discretionary matching contribution equal to 100% of compensation deferrals not to exceed 6% of eligible compensation. The Company contributed approximately $1.0 million, $0.9 million, and $0.7 million for the years ended December 31, 2019, 2018, and 2017, respectively, to the plan.

13. Income Taxes

The income tax provision is comprised of the following (in thousands):

	Year Ended December 31,
	2019		2018			2017
Current:
Federal	$	—	$	—		$	(99	)
State	—		—			—
Total current income tax expense (benefit)	—		—			(99		)
Deferred:
Federal	48,243		72,898			48,631
State	8,403		12,697			4,371
Total deferred income tax (benefit) expense	56,646		85,595			53,002
Change in valuation allowance	—		(47,628		)	(53,002		)
Income tax expense (benefit)	$	56,646	$	37,967		$	(99	)

A reconciliation of expected federal income taxes on income from continuing operations at statutory rates with the expense (benefit) for income taxes is presented in the following table (in thousands):

	Year Ended December 31,
	2019			2018			2017
Federal income tax at statutory rate	$	44,106		$	62,578		$	48,410
State income taxes, net of federal tax	8,403			12,697			4,371
Impact of tax reform, net of valuation allowance	—			—			(99		)
Valuation allowance	—			(47,628		)	(53,002		)
Goodwill impairment	—			8,549			—
Other	4,137			1,771			221
Income tax expense (benefit)	$	56,646		$	37,967		$	(99	)
Effective rate expressed as a percentage	27		%	13		%	—		%

The change in the Federal tax rate in 2017 was due to the passage of Public Law No. 115-97, commonly referred to as the Tax Cuts and Jobs Act ("TCJA"). The passage of this legislation resulted in the change in the U.S. statutory rate from 35% to 21%. Based on the Company's current interpretation and subject to the release of the related regulations and any future interpretive guidance, the effects of the change in tax law have been incorporated herein, and no substantial changes were identified compared to December 31, 2017.

In assessing the realizability of deferred tax assets, the Company considers whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income, and tax planning strategies in making this assessment. Judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits, and other deferred tax assets will be utilized prior to

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their expiration. As a result, it may be determined that a deferred tax asset valuation allowance should be established or released. Any increases or decreases in a deferred tax asset valuation allowance would impact net income through offsetting changes in income tax expense.

The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities at each of the period ends is presented in the following table (in thousands):

	As of December 31,
	2019			2018
Deferred tax assets (liabilities):
Net operating loss carryforward	$	71,921		$	111,587
Stock-based compensation	7,327			6,984
Basis of oil and gas properties	(179,831		)	(150,080		)
Statutory depletion	2,262			2,434
Unrealized loss on commodity derivative	2,907			(8,607		)
Other	801			(285		)
	(94,613		)	(37,967		)
Valuation allowance on tax assets	—			—
Deferred tax liability, net	$	(94,613	)	$	(37,967	)

During the year ended December 31, 2018, the Company concluded it is more likely than not it will realize the benefits of its net deferred tax assets by the end of 2018 as a result of current year ordinary income. This conclusion was based upon the Company’s cumulative positive net income for the three-year period ended December 31, 2018. In addition to the cumulative positive net income, the temporary deferred tax liabilities exceed the deferred tax assets resulting in the ability to utilize all deferred tax assets to offset future taxable income resulting from the reversal of the deferred tax liabilities.     

At December 31, 2019, the Company has U.S. Federal and state net operating loss carryforward of approximately $291.7 million that could be utilized to offset taxable income of future years. These net operating loss carryforwards will expire in various years beginning in 2025 with substantially all of the carryforwards expiring beginning in 2031.

As of December 31, 2019, the Company had no unrecognized tax benefits. The Company believes that there are no new items, nor changes in facts or judgments that should impact the Company’s tax position. Given the substantial NOL carryforwards at both the federal and state levels, it is anticipated that any changes resulting from a tax examination would simply adjust the carryforwards and would not result in significant interest expense or penalties. The Company's federal and state tax returns filed since December 31, 2016 and December 31, 2015, respectively, remain subject to examination by tax authorities.

14.    Revenue from Contracts with Customers

Under FASB Topic 606, Revenue from Contracts with Customers ("ASC 606"), sales of oil, natural gas, and NGLs are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. All of our contracts’ pricing provisions are tied to a market index, with certain adjustments based on, among other factors, whether a well delivers to a gathering or transmission line, quality of the oil or natural gas, and prevailing supply and demand conditions. As a result, the price of the oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies.

	Year Ended December 31,
Revenues (in thousands):	2019		2018		2017
Oil	$	506,303	$	494,052	$	261,505
Natural Gas and NGLs	129,199		151,589		101,011
	$	635,502	$	645,641	$	362,516

Natural Gas and NGLs Sales

Under the majority of our natural gas processing contracts, we deliver natural gas to a midstream processing entity at the wellhead or the inlet of the midstream processing entity’s system. The midstream processing entity gathers and processes the

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natural gas and remits proceeds to us for the resulting sales of NGLs and residue gas. For these contracts, we have concluded that the midstream processing entity is our customer. We recognize natural gas and NGL revenues based on the net amount of the proceeds received from the midstream processing entity.

Oil Sales

Our oil sales contracts are generally structured in one of the following ways:

• We sell oil production at the wellhead and collect an agreed-upon index price, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the wellhead at the net price received.

• We deliver oil to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes custody, title, and risk of loss of the product. Under this arrangement, we pay a third party to transport the product and receive a specified index price from the purchaser, net of pricing differentials. In this scenario, we recognize revenue when control transfers to the purchaser at the delivery point based on the price received from the purchaser. The third-party costs are recorded as transportation and gathering in our consolidated statements of operations.

Transaction Price Allocated to Remaining Performance Obligations

A significant number of our product sales are short-term in nature with a contract term of one year or less. For those contracts, we have utilized the practical expedient in ASC 606-10-50-14 exempting the Company from disclosure of the transaction price allocated to remaining performance obligations if the performance obligation is part of a contract that has an original expected duration of one year or less.

For our product sales that have a contract term greater than one year, we have utilized the practical expedient in ASC 606-10-50-14(a) which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore, future volumes are wholly unsatisfied, and disclosure of the transaction price allocated to remaining performance obligations is not required.

Contract Balances

Under our product sales contracts, we invoice customers once our performance obligations have been satisfied, at which point payment is unconditional. Accordingly, our product sales contracts do not typically give rise to contract assets or liabilities under ASC 606. As of December 31, 2019, we had no contract assets recorded. As of December 31, 2018, we had contract assets recorded within other current assets of $1.4 million representing cash advances to customers.

Prior-Period Performance Obligations

We record revenue in the month production is delivered to the purchaser. However, settlement statements for certain sales may not be received for 30 to 90 days after the date production is delivered, and as a result, we are required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. We record the differences between our estimates and the actual amounts received for product sales when that payment is received from the purchaser. We have existing internal controls for our revenue estimation process and related accruals, and any identified differences between our revenue estimates and actual revenue received historically have not been significant. For the years ended December 31, 2019 and 2018, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods was not material.

15.    Leases

The Company evaluates contractual arrangements at inception to determine if the agreement is a lease or contains an identifiable lease component as defined by ASC 842. When evaluating contracts to determine appropriate classification and recognition under ASC 842, significant judgment may be necessary to determine, among other criteria, if an embedded leasing arrangement exists, the length of the term, classification as either an operating or financing lease, whether renewal or termination options are reasonably certain to be exercised, and future lease payments to be included in the initial measurement of the ROU asset. Certain assumptions and judgments made by the Company when evaluating contracts that meet the definition of a lease under ASC 842 include:

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• Discount Rate - Unless implicitly defined, the Company will determine the present value of future lease payments using an estimated incremental secured borrowing rate based on a yield curve analysis that factors in certain assumptions, including the term of the lease and credit rating of the Company at lease commencement.

• Lease Term - The Company evaluates each contract containing a lease arrangement at inception to determine the length of the lease term when recognizing a ROU asset and corresponding lease liability. When determining the lease term, options available to extend or early terminate the arrangement are evaluated and included when it is reasonably certain these options will be exercised. There are no available options to extend that the Company is reasonably certain to exercise.

Currently, the Company has operating leases for asset classes that include office space, drilling rigs, and equipment rentals primarily used in development and field operations. The Company has financing leases for vehicles. We have provided a residual value guarantee for our vehicle leases. Certain leases also contain optional extension periods that allow for lease terms to be extended for up to an additional 5 years.

Costs associated with the Company’s operating leases are either expensed or capitalized depending on how the underlying asset is utilized. For example, costs associated with drilling rigs are capitalized as part of the development of the Company’s oil and gas properties. Refer to Note 1 for additional information on its accounting policies for oil and gas development and production activities. When calculating the Company’s ROU asset and liability, the Company considers all the necessary payments made or that are expected to be made upon commencement of the lease. Excluded from the initial measurement are certain variable lease payments.

The Company’s total lease costs were as follows (in thousands):

	Year Ended December 31, 2019
Finance lease cost:
Amortization of ROU assets	$	256
Interest on lease liabilities	31
Operating lease cost	3,799
Variable lease cost	729
Short-term lease cost 1	116,697
Total Lease Cost	$	121,512

¹ Costs associated with short-term lease agreements relate primarily to operational activities where underlying lease terms are less than or equal to one year. These costs primarily include drilling activities and field equipment rentals, and approximately 90% of these costs are capitalized to the consolidated balance sheet. It is expected that this amount will fluctuate primarily with the number of drilling rigs that the Company is operating under short-term agreements.

Other information related to the Company’s leases is as follows (in thousands, except lease terms and discount rates):

	December 31, 2019
Cash paid for amounts included in the measurement of lease liabilities
Operating cash flows from operating leases	$	4,244
Financing cash flows from finance leases	198
ROU assets obtained in exchange for new finance lease liabilities	186
ROU assets obtained in exchange for new operating lease liabilities	9,792

	As of December 31, 2019
Weighted-average remaining lease term - finance leases	2.6 years
Weighted-average remaining lease term - operating leases	1.7 years
Weighted-average discount rate - finance leases	4.75	%
Weighted-average discount rate - operating leases	4.75	%

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As of December 31, 2019 and through the date of issuance of these financial statements, the Company has no material lease arrangements which are scheduled to commence in the future. Maturities for the Company’s operating and finance lease liabilities included in the accompanying consolidated balance sheets as of December 31, 2019 were as follows (in thousands):

Year	Finance Leases			Operating Leases
2020	$	197		$	5,106
2021	224			2,113
2022	194			500
2023	38			—
2024	—			—
Thereafter	—			—
Total lease payments	$	653		$	7,719
Less imputed interest	(46		)	(287		)
Total lease liability	$	607		$	7,432

As of December 31, 2018, minimum future contractual payments were as follows (in thousands):

Year	Rig Contracts		Capital Leases		Operating Leases
2019	$	11,102	$	183	$	896
2020	—		186		916
2021	—		204		913
2022	—		167		500
2023	—		—		—
Thereafter	—		—		—

Amounts recorded in the Company’s accompanying consolidated balance sheets were as follows (in thousands):

As of December 31, 2019	Financing Leases		Operating Leases
Other property and equipment, net	$	670	$	—
Other assets	—		6,037
Accounts payable and accrued expenses	173		4,881
Other liabilities	434		2,551
	$	607	$	7,432

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16. Other Commitments and Contingencies

Oil Commitments

The Company has entered into firm sales agreements for its oil production with five counterparties. Deliveries under the sales agreements have commenced. Pursuant to these agreements, we must deliver specific amounts of oil either from our own production or from oil that we acquire from third parties. If we are unable to fulfill all of our contractual obligations, we may be required to pay penalties or damages pursuant to these agreements. Our commitments, excluding the contingent commitment described below, are as follows:

Year ending December 31:	Oil (MBbls)
2020	9,493
2021	7,147
2022	5,475
2023	5,475
2024	5,490
Thereafter	9,120
Total	42,200

During the year ended December 31, 2017, the Company incurred transportation deficiency charges of $0.7 million. During the years ended December 31, 2019 and 2018, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed.

Natural Gas Commitments

In collaboration with several other producers and DCP Midstream, LP ("DCP Midstream"), we entered into two facilities expansion agreements with DCP Midstream to expand and improve its natural gas gathering pipelines and processing facilities. DCP Midstream completed and turned on line the first of the two 200 MMcf per day plants in August 2018. The second plant was placed into service during the third quarter of 2019. We are bound to the volume requirements in these agreements on the first day of the calendar month following the actual in-service date of the relevant plant. Both agreements require baseline volume commitments, consisting of our gross wellhead volume delivered in November 2016 to DCP Midstream, and incremental wellhead volume commitments of 46.4 MMcf per day and 43.8 MMcf per day for the first and second agreements, respectively, for 7 years. If we are unable to fulfill all of our contractual obligations and our obligations are not sufficiently reduced by the collective volumes delivered by other producers, we may be required to pay penalties or damages pursuant to these agreements. We are also required for the first three years of the contracts to guarantee a certain target profit margin to DCP Midstream on these incremental volumes. During the years ended December 31, 2019, 2018, and 2017, we were able to meet all of our delivery obligations, and we anticipate that our current gross operated production will continue to meet our future delivery obligations, although this cannot be guaranteed. During the years end December 31, 2018 and 2017, we were not required to make any payments related to DCP Midstream's guaranteed profit margin. During the year ended December 31, 2019, payments related to DCP Midstream's guaranteed profit margin were not significant.

Litigation

From time to time, the Company is a party to various commercial and regulatory claims, pending or threatened legal action, and other proceedings that arise in the ordinary course of business. It is the opinion of management that none of the current proceedings are reasonably likely to have a material adverse impact on the Company's business, financial position, results of operations, or cash flows.

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17. Supplemental Schedule of Information to the Consolidated Statements of Cash Flows

The following table supplements the cash flow information presented in the consolidated financial statements for the periods presented (in thousands):

	Year Ended December 31,
Supplemental cash flow information:	2019			2018			2017
Interest paid	$	41,871		$	36,134		$	9,235
Income taxes paid	$	—		$	—		$	—
Non-cash investing and financing activities:
Accrued well costs as of period end	$	72,121		$	130,784		$	54,877
Asset retirement obligations incurred with development activities	2,311			4,174			3,398
Asset retirement obligations assumed with acquisitions	—			26,150			24,696
Obligations discharged with asset retirements and divestitures	$	(11,712	)	$	(12,267	)	$	(14,332	)
Net changes in operating assets and liabilities:
Accounts receivable	$	36,492		$	(29,521	)	$	(72,518	)
Accounts payable and accrued expenses	2,021			697			5,823
Revenue payable	1,734			30,219			47,345
Production taxes payable	4,593			38,489			33,311
Other	(4,118		)	(341		)	(1,131		)
Changes in operating assets and liabilities	$	40,722		$	39,543		$	12,830

18. Unaudited Oil and Natural Gas Reserves Information

Oil and Natural Gas Reserve Information:  Proved reserves are the estimated quantities of oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (prices and costs held constant as of the date the estimate is made).  Proved developed reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.  Proved undeveloped reserves are 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.

Proved oil and natural gas reserve information as of the period ends presented and the related discounted future net cash flows before income taxes are based on estimates prepared by Ryder Scott.  Reserve information for the properties was prepared in accordance with guidelines established by the SEC.

The reserve estimates prepared as of each of the period ends presented were prepared in accordance with applicable SEC rules.  Proved oil and natural gas reserves are calculated based on the prices for oil and natural gas during the twelve-month period before the determination date, determined as the unweighted arithmetic average of the first day of the month price for each month within such period.  This average price is also used in calculating the aggregate amount and changes in future cash inflows related to the standardized measure of discounted future cash flows.  Undrilled locations can generally be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking.

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The following table sets forth information regarding the Company’s net ownership interests in estimated quantities of proved developed and undeveloped oil and natural gas reserve quantities and changes therein for each of the periods presented:

	Oil (MBbl)		Natural Gas (MMcf)		NGL (MBbl)		MBOE
Balance, December 31, 2016	38,032		331,921		—		93,352
Revision of previous estimates	(3,038	)	(66,413	)	28,689		14,581
Purchase of reserves in place	12,150		117,167		13,424		45,103
Extensions, discoveries, and other additions	28,736		206,644		24,358		87,535
Sale of reserves in place	(660	)	(4,592	)	—		(1,425	)
Production	(5,824	)	(24,834	)	(2,518	)	(12,481	)
Balance, December 31, 2017	69,396		559,893		63,953		226,665
Revision of previous estimates	1,718		41,393		5,589		14,205
Purchase of reserves in place	5,398		63,367		6,474		22,433
Extensions, discoveries, and other additions	19,892		144,337		16,946		60,894
Sale of reserves in place	—		—		—		—
Production	(8,392	)	(37,123	)	(3,869	)	(18,448	)
Balance, December 31, 2018	88,012		771,867		89,093		305,749
Revision of previous estimates	(13,471	)	(105,645	)	(20,378	)	(51,456	)
Purchase of reserves in place	—		—		—		—
Extensions, discoveries, and other additions	16,159		180,152		17,694		63,879
Sale of reserves in place	(299	)	(963	)	(117	)	(576	)
Production	(9,813	)	(49,471	)	(4,526	)	(22,584	)
Balance, December 31, 2019	80,588		795,940		81,766		295,012
Proved developed and undeveloped reserves:
Developed at December 31, 2017	26,552		219,279		24,251		87,350
Undeveloped at December 31, 2017	42,844		340,614		39,702		139,315
Balance, December 31, 2017	69,396		559,893		63,953		226,665
Developed at December 31, 2018	37,102		324,169		36,427		127,557
Undeveloped at December 31, 2018	50,910		447,698		52,666		178,192
Balance, December 31, 2018	88,012		771,867		89,093		305,749
Developed at December 31, 2019	32,965		344,823		34,733		125,169
Undeveloped at December 31, 2019	47,623		451,117		47,033		169,843
Balance, December 31, 2019	80,588		795,940		81,766		295,012

Notable changes in proved reserves for the year ended December 31, 2019 included:

• Revision of previous estimates. For the year ended December 31, 2019, revisions to previous estimates decreased proved developed and undeveloped reserves by a net amount of 51,456 MBOE primarily as a result of lower pricing, an extended timeline for the planned development activities, and a reduction of expected recoveries.

• Extensions and discoveries. For the year ended December 31, 2019, total extensions and discoveries of 63,879 MBOE were primarily attributable to extending our development plan by a year due to the passage of time and the drilling and completion of wells not previously proved.

Notable changes in proved reserves for the year ended December 31, 2018 included:

• Purchases of reserves in place. For the year ended December 31, 2018, purchases of reserves in place of 22,433 MBOE were attributable to the various acquisitions executed during the year. See Note 3 for further information.

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• Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,205 MBOE primarily as a result of increasing our density of proved undeveloped reserves.

• Extensions and discoveries. For the year ended December 31, 2018, total extensions and discoveries of 60,894 MBOE were primarily attributable to extending our development plan by a year due to the passage of time and the drilling and completion of wells not previously proved.

Notable changes in proved reserves for the year ended December 31, 2017 included:

• Purchases of reserves in place. For the year ended December 31, 2017, purchases of reserves in place of 45,103 MBOE were primarily attributable to the acquisition of proved reserves in the GCII Acquisition. See Note 3 for further information.

• Revision of previous estimates. For the year ended December 31, 2017, revisions to previous estimates increased proved developed and undeveloped reserves by a net amount of 14,581 MBOE primarily as a result of updated pricing as well as shifting from reporting reserves on a 2-stream to a 3-stream basis.

• Extensions and discoveries. For the year ended December 31, 2017, total extensions and discoveries of 87,535 MBOE were primarily attributable to extending our development plan by a year due to the passage of time, the addition of a third rig for the second and third years of our development plan, and the drilling and completion of wells not previously proved.

Standardized Measure of Discounted Future Net Cash Flows

The following discussion relates to the standardized measure of future net cash flows from our proved reserves and changes therein related to estimated proved reserves.  Future oil and natural gas sales have been computed by applying average prices of oil and natural gas as discussed below.  Future production and development costs were computed by estimating the expenditures to be incurred in developing and producing the proved oil and natural gas reserves at the end of the period based on period-end costs.  The calculation assumes the continuation of existing economic conditions, including the use of constant prices and costs.  Future income tax expenses were calculated by applying period-end statutory tax rates, with consideration of future tax rates already legislated, to future pretax cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved and tax credits and loss carryforwards relating to oil and natural gas producing activities.  All cash flow amounts are discounted at 10% annually to derive the standardized measure of discounted future cash flows.  Actual future cash inflows may vary considerably, and the standardized measure does not necessarily represent the fair value of the Company’s oil and natural gas reserves.  Actual future net cash flows from oil and gas properties will also be affected by factors such as actual prices the Company receives for oil and natural gas, the amount and timing of actual production, supply of and demand for oil and natural gas, and changes in governmental regulations or taxation.

The following table sets forth the Company’s future net cash flows relating to proved oil and natural gas reserves based on the standardized measure prescribed by the SEC (in thousands):

	As of December 31,
	2019			2018			2017
Future cash inflow	$	6,181,423		$	8,831,319		$	5,493,507
Future production costs	(1,595,045		)	(2,082,036		)	(1,291,369		)
Future development costs	(1,320,071		)	(1,372,511		)	(1,048,856		)
Future income tax expense	(294,967		)	(759,280		)	(285,349		)
Future net cash flows	2,971,340			4,617,492			2,867,933
10% annual discount for estimated timing of cash flows	(1,205,682		)	(1,941,844		)	(1,267,258		)
Standardized measure of discounted future net cash flows	$	1,765,658		$	2,675,648		$	1,600,675

There have been significant fluctuations in the posted prices of oil and natural gas during the last three years.  Prices actually received from purchasers of the Company’s oil and natural gas are adjusted from posted prices for location differentials, quality differentials, and Btu content. Estimates of the Company’s reserves are based on realized prices.

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The following table presents the prices used to prepare the reserve estimates based upon the unweighted arithmetic average of the first day of the month price for each month within the twelve-month period prior to the end of the respective reporting period presented as adjusted for our differentials:

	Oil (Bbl)		Natural Gas (Mcf)		NGL (Bbl)
December 31, 2019 (Average)	$	50.17	$	1.69	$	9.67
December 31, 2018 (Average)	$	61.23	$	2.07	$	20.74
December 31, 2017 (Average)	$	46.57	$	2.21	$	16.06

The prices for the December 31, 2019 oil and natural gas reserves are based on the twelve-month arithmetic average for the first of month prices as adjusted for our differentials from January 1, 2019 through December 31, 2019. The December 31, 2019 oil price of $50.17 per barrel (West Texas Intermediate Cushing) was $11.06 lower than the December 31, 2018 oil price of $61.23 per barrel. The December 31, 2019 natural gas price of $1.69 per Mcf (Henry Hub) was $0.38 lower than the December 31, 2018 price of $2.07 per Mcf.

Changes in the Standardized Measure of Discounted Future Net Cash Flows:  The principle sources of change in the standardized measure of discounted future net cash flows are (in thousands):

	Year Ended December 31,
	2019			2018			2017
Standardized measure, beginning of period	$	2,675,648		$	1,600,675		$	434,261
Sale and transfers, net of production costs	(526,212		)	(533,385		)	(306,754		)
Net changes in prices and production costs	(913,844		)	538,404			135,525
Extensions, discoveries, and improved recovery	357,895			760,575			811,564
Changes in estimated future development costs	129,369			(23,712		)	(25,969		)
Previously estimated development costs incurred during the period	170,320			248,739			170,296
Revision of quantity estimates	(515,285		)	176,264			165,267
Accretion of discount	316,115			175,628			47,635
Net change in income taxes	281,316			(329,894		)	(113,523		)
Divestitures of reserves	(12,031		)	—			(7,157		)
Purchase of reserves in place	—			176,707			260,999
Changes in timing and other	(197,633		)	(114,353		)	28,531
Standardized measure, end of period	$	1,765,658		$	2,675,648		$	1,600,675

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