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volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;

•	the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the COVID-19 pandemic and the actions by certain oil and natural gas producing countries;

•	our business strategy and future drilling plans;

•	our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;

•	our drilling prospects, inventories, projects and programs;

•	our financial strategy, liquidity and capital required for our development program;

•	our realized oil, natural gas and NGL prices;

•	the timing and amount of our future production of oil, natural gas and NGLs;

•	our hedging strategy and results;

•	our competition and government regulations;

•	our ability to obtain permits and governmental approvals;

•	our pending legal or environmental matters;

•	the marketing and transportation of our oil, natural gas and NGLs;

•	our leasehold or business acquisitions;

•	cost of developing our properties;

•	our anticipated rate of return;

•	general economic conditions;

•	credit markets;

•	uncertainty regarding our future operating results; and

•	our plans, objectives, expectations and intentions contained in this Quarterly Report that are not historical.

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(1)	Included in Prepaid and other current assets and Other noncurrent assets line items in the Consolidated Balance Sheets.

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Note 1—Basis of Presentation and Summary of Significant Accounting Policies

Description of Business

Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of unconventional oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and its properties consist of large, contiguous acreage blocks located in West Texas and New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Centennial” or the “Company” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).

Principles of Consolidation and Basis of Presentation

The accompanying unaudited consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”) for interim financial reporting. Accordingly, certain disclosures normally included in an Annual Report on Form 10-K have been omitted. The consolidated financial statements and related notes included in this Quarterly Report should be read in conjunction with the Company’s consolidated financial statements and related notes included in the Company’s Annual Report on Form 10-K for the period ended December 31, 2019 (the “2019 Annual Report”). Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Company’s 2019 Annual Report.

In the opinion of management, all normal, recurring adjustments and accruals considered necessary to present fairly, in all material respects, the Company’s interim financial results have been included. Operating results for the periods presented are not necessarily indicative of expected results for the full year.

The consolidated financial statements include the accounts of the Company and its subsidiary CRP, and CRP’s wholly-owned subsidiaries. Noncontrolling interest represents third-party ownership in CRP and is presented as a component of equity. As of December 31, 2019, the noncontrolling interest ownership of CRP was 0.4%.

On April 2, 2020, the legacy owners of CRP converted all of their remaining 1,034,119 CRP Common Units (and corresponding shares of Class C Common Stock) into Class A Common Stock (the “Conversion”), which eliminated the noncontrolling interest ownership in CRP. As a result, CRP was a wholly-owned subsidiary of Centennial Resource Development, Inc. for the three month period ended June 30, 2020. No cash proceeds were received by the Company in connection with the Conversion, and deferred tax expense of $2.2 million was recorded in equity with an offsetting deferred tax liability for the same amount, upon conversion.

Use of Estimates

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

The more significant areas requiring the use of assumptions, judgments and estimates include: (i) oil and natural gas reserves; (ii) cash flow estimates used in impairment tests for long-lived assets; (iii) impairment expense of unproved properties; (iv) depreciation, depletion and amortization; (v) asset retirement obligations; (vi) determining fair value and allocating purchase price in connection with business combinations and asset acquisitions; (vii) accrued revenues and related receivables; (viii) accrued liabilities; (ix) valuation of derivatives; and (x) deferred income taxes.

Income Taxes

Historically, CRP has been treated as a partnership for U.S. federal and most applicable state and local income tax purposes. As a partnership, CRP was not subject to U.S. federal and certain state and local income taxes, and any taxable income or loss generated by CRP was passed through to and included in the taxable income or loss of its members, including Centennial Resource Development, Inc., on a pro rata basis. Following the Conversion, CRP is no longer a partnership for tax purposes. As a result, the deferred tax assets and liabilities previously recorded within the partnership, and previously reported by the Company as a net deferred tax balance related to its investment in the CRP partnership, are now directly included within the Company’s

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deferred tax assets and liabilities. Further, the Company is now subject to U.S. federal and applicable state and local income taxes for its entire consolidated taxable income or loss.

Income tax expense recognized during interim periods is based on applying an estimated annual effective income tax rate to the Company’s year-to-date income, plus any significant unusual or infrequently occurring items which are recorded in the interim period. The computation of the annual estimated effective tax rate at each interim period requires certain estimates and significant judgment including, but not limited to, the expected operating income for the year, projections of the proportion of income earned and taxed in various state jurisdictions, permanent and temporary differences and the likelihood of recovering deferred tax assets generated. The accounting estimates used to compute the provision for income taxes may change as new events occur, additional information becomes known or as the tax environment changes.

During the first half of 2020, the Company determined that it is more-likely-than-not that a portion of its deferred tax assets will not be realized. Accordingly, a valuation allowance against its deferred tax assets in the amount of $49.7 million was recognized as of June 30, 2020, which caused the Company’s provision for income taxes for the three and six months ended June 30, 2020 to differ from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book loss.

Risks and Uncertainties

The prices received for oil, natural gas and NGL production heavily influence the Company’s revenue, profitability, liquidity, access to capital, future rate of growth and carrying value of its properties. Oil, natural gas and NGLs are commodities, and their prices have been volatile in response to recent changes in global and domestic supply, the global COVID-19 pandemic and demand, and market uncertainty. The Company generally funds its operations and capital expenditures with its cash flows from operations, borrowings under CRP’s credit agreement, and offerings of debt and equity securities. The Company expects to be able to fund its operations, planned capital expenditures and working capital requirements during the next 12 months and the foreseeable future. However, continued volatility of oil and gas prices could have an adverse effect on the Company’s future business, financial condition, results of operations, operating cash flows, liquidity, production levels and quantities of oil and gas reserves that may be economically produced, which could in turn impact the Company’s ability to comply with the financial covenants under its borrowing agreements and could also limit the amount of borrowings available to fund the Company’s capital expenditures and potential acquisitions. Additionally, if forward prices decline, the Company could incur additional impairments of its oil and gas assets.

Note 2—Property Divestiture

On February 24, 2020, the Company entered into a purchase and sale agreement (the “Agreement”) to sell certain of its water disposal assets. On May 15, 2020, the Agreement was terminated after the purchaser failed to close the transaction as set forth in the Agreement.

The purchaser deposited $10.0 million of cash in an escrow account (the “Deposit”) which, in the event of termination, was to be distributed to the Company or the purchaser in accordance with the remedy provisions of the Agreement. Centennial believes it has a right to receive the Deposit, pursuant to the terms of the Agreement. However, the purchaser advised the Company that it disputes this position, and as a result, the distribution of the Deposit is under ongoing litigation between the Company and the purchaser.

Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses

Accounts receivable are comprised of the following:

(in thousands)	June 30, 2020				December 31, 2019
Accrued oil and gas sales receivable, net	$	41,525			$	76,578
Joint interest billings, net	22,451				25,136
Other	119				198
Accounts receivable, net	$	64,095			$	101,912

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Accounts payable and accrued expenses are comprised of the following:

(in thousands)	June 30, 2020				December 31, 2019
Accounts payable	$	8,754			$	21,484
Accrued capital expenditures	18,765				83,002
Revenues payable	42,633				82,539
Accrued interest	15,466				19,405
Accrued derivative settlements payable	11,569				—
Accrued employee compensation and benefits	6,167				12,979
Accrued expenses and other	19,006				24,900
Accounts payable and accrued expenses	$	122,360			$	244,309

Note 4—Long-Term Debt

The following table provides information about the Company’s long-term debt as of the dates indicated:

(in thousands)	June 30, 2020				December 31, 2019
Credit Facility due 2023	$	370,000			$	175,000
8.00% Senior Secured Notes due 2025	127,073				—
5.375% Senior Notes due 2026	289,448				400,000
6.875% Senior Notes due 2027	356,351				500,000
Unamortized debt issuance costs on Senior Notes	(13,646		)		(14,061		)
Unamortized debt discount	(23,183		)		(3,550		)
Senior Notes, net	736,043				882,389
Total long-term debt, net	$	1,106,043			$	1,057,389

Credit Agreement

CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). On May 1, 2020, CRP, as borrower, and the Company, as parent guarantor, entered into the second and third amendments to the Credit Agreement (the “2020 Amendments”), which, among other things, established a new borrowing base and level of elected commitments of $700.0 million. The 2020 Amendments that the lenders approved also permitted the issuance of the Senior Secured Notes in connection with the Debt Exchange (defined below), and they implemented an availability blocker equal to 25% of the newly issued amount of Senior Secured Notes. As of June 30, 2020, the Company had $370.0 million in borrowings outstanding and $290.0 million in available borrowing capacity, which was net of $8.2 million in letters of credit outstanding and the availability blocker of $31.8 million.

The amount available to be borrowed under CRP’s Credit Agreement is equal to the lesser of (i) the borrowing base less the availability blocker, (ii) aggregate elected commitments, which was set at $700.0 million pursuant to the 2020 Amendments, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually in the spring and fall by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company.

Borrowings under the Credit Agreement may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements and subject to 1% floor) plus an applicable margin, which ranged from 200 to 300 basis points as of June 30, 2020, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin, which ranged from 100 to 200 basis

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points as of June 30, 2020, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused amounts under its facility.

CRP’s Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of the Company’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.

CRP’s Credit Agreement also requires it to maintain compliance with the following financial ratios:

(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under its revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due under the credit agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;

(ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and

(iii) a leverage ratio, as also defined in the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to the 2020 Amendments, the leverage ratio is suspended until March 31, 2022, at which time, the ratio may not exceed 5.00 to 1.00, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at not greater than 4.0 to 1.0.

CRP was in compliance with the covenants and the financial ratios described above as of June 30, 2020 and through the filing of this Quarterly Report.

Senior Unsecured Note Debt Exchange

On May 22, 2020, CRP completed its private exchange of debt pursuant to which a $254.2 million aggregate principal amount of Senior Unsecured Notes (defined below) was validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount (the “Debt Exchange”) of newly issued 8.00% second lien senior secured notes due 2025 (the “Senior Secured Notes”).

Whether a debt exchange should be accounted for pursuant to Financial Accounting Standards Board’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments, requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. As it was determined that Centennial was not experiencing financial difficulty and could obtain funds at market rates it could afford (i.e. non-investment grade but nontroubled debtor rates), the Company’s Debt Exchange was accounted for as an extinguishment of debt in accordance with ASC 470-50. As a result, a gain on the exchange of debt of $143.4 million was recognized in the Consolidated Statement of Operations, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of new Senior Secured Notes issued, net of their associated debt discount of $21.0 million (which was based on the notes’ estimated fair value on the exchange date).

Senior Secured Notes

In connection with the Debt Exchange, on May 22, 2020, the Company issued $127.1 million aggregate principal amount of Senior Secured Notes. The Senior Secured Notes were recorded at their fair value on the date of issuance equal to 83.44% of par (a debt discount of $21.0 million) and net of their associated debt issuance costs of $4.2 million. The Senior Secured Notes bear interest at an annual rate of 8.00% and are due on June 1, 2025. Interest is payable semi-annually in arrears on each June 1 and December 1, commencing on December 1, 2020.

The Senior Secured Notes are guaranteed, subject to certain exceptions, by the Company and each of CRP’s subsidiaries and are secured on a second-priority basis (subject in priority only to certain exceptions) by substantially all of the assets of CRP and the Company, including deposit accounts and substantially all proved reserves and undeveloped acreage.

The Company has the option to redeem all (but not less than all) of the Senior Secured Notes, at any time prior to May 22, 2021 on a single occasion, at a redemption price equal to 100% of the principal amount, plus accrued and unpaid interest to the date of redemption, if such redemption is made entirely with proceeds from equity offerings or the issuance of unsecured indebtedness.

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At any time prior to June 1, 2022, the Company has the option to redeem the Senior Secured Notes, in whole or in part, at a redemption price equal to 100% of the principal amount of the Senior Secured Notes redeemed plus accrued and unpaid interest and a “make-whole” premium. The Senior Secured Notes are redeemable at the Company’s option, in whole or in part, at any time on or after June 1, 2022, at specified redemption prices, together with accrued and unpaid interest. In addition, at any time prior to June 1, 2022, the Company may redeem up to 35% of the aggregate principal amount of each of the Senior Secured Notes, including any permitted additional Senior Secured Notes, with an amount of cash not greater than the net proceeds of certain equity offerings at a redemption price equal to 108% of the principal amount of such Senior Secured Notes, plus any accrued and unpaid interest to, but excluding, the redemption date.

Senior Unsecured Notes

On March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes”) in a 144A private placement at a price equal to 99.235% of par that resulted in net proceeds to CRP of $489.0 million, after deducting the original issuance discount of $3.8 million and debt issuance costs of $7.2 million. Interest is payable on the 2027 Senior Notes semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2019. In May 2020 in connection with the Debt Exchange, $143.7 million aggregate principal amount of the 2027 Senior Notes was exchanged for Senior Secured Notes. As of June 30, 2020, the remaining aggregate principal amount of 2027 Senior Notes outstanding was $356.4 million.

On November 30, 2017, CRP issued at par $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes” and collectively with the 2027 Senior Notes, the “Senior Unsecured Notes”) in a 144A private placement that resulted in net proceeds to CRP of $391.0 million, after deducting $9.0 million in debt issuance costs. Interest is payable on the 2026 Senior Notes semi-annually in arrears on each January 15 and July 15, which commenced on July 15, 2018. In May 2020 in connection with the Debt Exchange, $110.6 million aggregate principal amount of the 2026 Senior Notes was exchanged for Senior Secured Notes. As of June 30, 2020, the remaining aggregate principal amount of 2026 Senior Notes outstanding was $289.4 million.

The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.

At any time prior to January 15, 2021 (for the 2026 Senior Notes) and April 1, 2022 (for the 2027 Senior Notes), the “Optional Redemption Dates,” CRP may, on any one or more occasions, redeem up to 35% of the aggregate principal amount of either series of Senior Unsecured Notes with an amount of cash not greater than the net cash proceeds of certain equity offerings at a redemption price equal to 105.375% (for the 2026 Senior Notes) and 106.875% (for the 2027 Senior Notes) of the principal amount of the Senior Unsecured Notes of the applicable series redeemed, plus any accrued and unpaid interest to the date of redemption; provided that at least 65% of the aggregate principal amount of each such series of Senior Unsecured Notes remains outstanding immediately after such redemption, and the redemption occurs within 180 days of the closing date of such equity offering.

At any time prior to the Optional Redemption Dates, CRP may, on any one or more occasions, redeem all or a part of the Senior Unsecured Notes at a redemption price equal to 100% of the principal amount of the Senior Unsecured Notes redeemed, plus a “make-whole” premium, and any accrued and unpaid interest as of the date of redemption. On and after the Optional Redemption Dates, CRP may redeem the Senior Unsecured Notes, in whole or in part, at redemption prices expressed as percentages of principal amount plus accrued and unpaid interest to the redemption date.

Senior Notes

The following section discusses the general terms of the indentures applicable to the Company’s Senior Unsecured Notes and the Senior Secured Notes (collectively, the “Senior Notes”).

The indentures governing the Senior Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of June 30, 2020 and through the filing of this Quarterly Report.

Upon an Event of Default (as defined in the indentures governing the Senior Notes), the trustee or the holders of at least 25% of the aggregate principal amount of then outstanding Senior Notes may declare the Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to CRP, any restricted subsidiary of CRP that is a significant subsidiary, or any group of restricted subsidiaries that, taken together, would constitute a significant subsidiary, will automatically cause all outstanding Senior Notes to become due and payable.

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If CRP experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Notes may require CRP to repurchase all or a portion of its Senior Notes for cash at a price equal to 101% of the aggregate principal amount of such Senior Notes, plus any accrued but unpaid interest to the date of repurchase.

Note 5—Asset Retirement Obligations

The following table summarizes changes in the Company’s asset retirement obligations (“ARO”) associated with its working interests in oil and gas properties for the six months ended June 30, 2020:

(in thousands)
Asset retirement obligations, beginning of period	$	16,874
Liabilities incurred and acquired	630
Liabilities divested and settled	(34		)
Accretion expense	538
Revisions to estimated cash flows	59
Asset retirement obligations, end of period	$	18,067

ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and natural gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous assumptions and judgments including the ultimate plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liability, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability and as accretion expense.

Note 6—Stock-Based Compensation

On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), which authorized an aggregate of 16,500,000 shares of Class A Common Stock for issuance. On April 29, 2020, the stockholders of the Company approved the amended and restated LTIP, which, among other things, increased the number of shares of Class A Common Stock authorized for issuance by 8,250,000 shares. As of June 30, 2020, the Company had 14,763,345 shares of Class A Common Stock available for future grants. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units, stock appreciation rights and other stock or cash-based awards.

During the three months ended June 30, 2020, as a result of the decline in crude oil and natural gas prices, ongoing uncertainty regarding the oil supply-demand macro environment and the related suspension of the Company’s drilling and completion activities, the Company implemented a reduction to its workforce. In connection with this reduction, the Compensation Committee of the Company’s Board of Directors approved an accelerated partial vesting of certain unvested stock options and restricted stock awards held by 32 of the terminated employees. The acceleration changed the terms of the vesting conditions and are therefore treated as modifications in accordance with ASC Topic 718, Compensation-Stock Compensation. The modification resulted in a decrease to total stock-based compensation expense of $2.5 million associated with the decrease in the fair value of the modified awards compared to the original awards’ fair value. The shares and options that were accelerated are included within the vested line item in the below tables.

Stock-based compensation expense is recognized within both General and administrative expenses and Exploration expense in the Consolidated Statements of Operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.

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The following table summarizes stock-based compensation expense recognized for the periods presented:

	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands)	2020				2019				2020				2019
Restricted stock awards	$	3,387			$	3,408			$	7,741			$	6,590
Stock option awards	291				2,625				1,275				5,209
Performance stock units	1,003				725				2,006				1,442
Other stock-based compensation expense(1)	46				—				114				—
Total stock-based compensation expense	$	4,727			$	6,758			$	11,136			$	13,241

(1)	Includes expenses related to the Company’s Employee Stock Purchase Plan (the “ESPP”). In May 2019, an aggregate of 2,000,000 shares were authorized by stockholders for issuance under the ESPP, which became effective on July 1, 2019. As of June 30, 2020, the Company had 1,940,801 shares of Class A Common Stock available for future issuance.

Restricted Stock

The following table provides information about restricted stock activity during the six months ended June 30, 2020:

	Awards			Weighted Average Grant-Date Fair Value
Unvested balance as of December 31, 2019	4,838,996			$	8.51
Granted	1,385,235			2.53
Vested	(540,402	)		8.52
Forfeited	(757,975	)		5.81
Unvested balance as of June 30, 2020	4,925,854			6.90

The Company grants service-based restricted stock awards to executive officers and employees, which vest ratably over a three-year service period, and to directors, which vest over a one-year service period. Compensation cost for the service-based restricted stock awards is based on the closing market price of the Company’s Class A common stock on the grant date, and such costs are recognized ratably over the applicable vesting period. The weighted average grant-date fair value for restricted stock awards granted during the period was $2.53 and $12.48 per share for the six months ended June 30, 2020 and 2019, respectively. The total fair value of restricted stock awards that vested during the six months ended June 30, 2020 and 2019 was $4.6 million and $1.5 million, respectively, and includes awards with vesting terms that were accelerated as discussed above. Unrecognized compensation cost related to restricted shares that were unvested as of June 30, 2020 was $21.7 million, which the Company expects to recognize over a weighted average period of 1.9 years.

Stock Options

Stock options that have been granted under the LTIP expire ten years from the grant date and vest ratably over a three-year service period. The exercise price for an option granted under the LTIP is the closing market price of the Company’s Class A Common Stock on the grant date.

Compensation cost for stock options is based on the grant-date fair value of the award which is then recognized ratably over the vesting period of three years. The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the weighted average asset volatility of the Company and an identified set of comparable companies. Expected term is based on the simplified method and is estimated as the mid-point between the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.

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The following table summarizes the assumptions and related information used to determine the grant-date fair value of stock option awards for the periods presented:

	Six Months Ended June 30,
	2020				2019
Weighted average grant-date fair value per share	$	1.16			$	4.77
Expected term (in years)	6				6
Expected stock volatility	86		%		46		%
Dividend yield	—		%		—		%
Risk-free interest rate	1.0		%		2.4		%

The following table provides information about stock option awards outstanding during the six months ended June 30, 2020:

	Options			Weighted Average Exercise Price				Weighted Average Remaining Term (in years)		Aggregate Intrinsic Value (in thousands)
Outstanding as of December 31, 2019	4,764,167			$	15.99
Granted	124,000			2.13
Exercised	—			—
Forfeited	(94,409	)		13.99
Expired	(2,086,164	)		16.34
Outstanding as of June 30, 2020	2,707,594			15.15				6.4		$	40
Exercisable as of June 30, 2020	2,136,070			15.95				5.9		$	—

The total fair value of stock options that vested during the six months ended June 30, 2020 and 2019 was $4.2 million and $4.1 million, respectively, and includes awards with vesting terms that were accelerated as discussed above. There were no stock options exercised during either the six months ended June 30, 2020 or 2019. As of June 30, 2020, there was $1.8 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro-rata basis over a weighted-average period of 1.4 years.

Performance Stock Units

Note 7—Derivative Instruments

The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.

Commodity Derivative Contracts

Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flows from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.

Commodity Swap Contracts. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production as well as basis swaps to hedge the difference between the index price and a local index price. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.

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The following table summarizes the approximate volumes and average contract prices of swap contracts the Company had in place as of June 30, 2020:

	Period		Volume (Bbls)			Volume (Bbls/d)			Weighted Average Fixed Price ($/Bbl)(1)
Crude oil swaps	July 2020 - September 2020		2,300,000			25,000			$	26.83
	October 2020 - December 2020		1,196,000			13,000			38.89
	Period		Volume (Bbls)			Volume (Bbls/d)			Weighted Average Differential ($/Bbl)(2)
Crude oil basis swaps	July 2020 - September 2020		1,472,000			16,000			$	0.52
	October 2020 - December 2020		874,000			9,500			0.61

(1)	These crude oil swap transactions are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period.

(2)	These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.

	Period		Volume (MMBtu)			Volume (MMBtu/d)			Weighted Average Fixed Price ($/MMBtu)(1)
Natural gas swaps	July 2020 - September 2020		2,760,000			30,000			$	2.03
	October 2020 - December 2020		2,150,000			23,370			2.40
	January 2021 - March 2021		1,800,000			20,000			2.68
	Period		Volume (MMBtu)			Volume (MMBtu/d)			Weighted Average Differential ($/MMBtu)(2)
Natural gas basis swaps	July 2020 - September 2020		2,760,000			30,000			$	(1.62	)
	October 2020 - December 2020		930,000			10,109			(1.62		)

(1)	These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period.

(2)	These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable settlement period.

Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes. Therefore, all gains and losses are recognized in the Company’s Consolidated Statements of Operations. All derivative instruments are recorded at fair value in the Consolidated Balance Sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.

The following table presents the impact of the Company’s derivative instruments in its Consolidated Statements of Operations for the periods presented:

	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands)	2020				2019				2020				2019
Net gain (loss) on derivative instruments	$	(29,857	)		$	2,128			$	(38,362	)		$	(3,743	)

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Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying Consolidated Balance Sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarizes the fair value amounts and the classification in the Consolidated Balance Sheets of the Company’s derivative contracts outstanding at the respective balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:

	Balance Sheet Classification		Gross Fair Value Asset/Liability Amounts				Gross Amounts Offset(1)				Net Recognized Fair Value Assets/Liabilities
(in thousands)			June 30, 2020
Derivative Assets
Commodity contracts	Current assets - Derivative instruments		$	2,861			$	(2,861	)		$	—
Derivative Liabilities
Commodity contracts	Current liabilities - Derivative instruments		34,601				(2,861		)		31,740
			December 31, 2019
Derivative Liabilities
Commodity contracts	Current liabilities - Derivative instruments		$	325			$	—			$	325

(1)	The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or contract termination.

Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under CRP’s credit agreement. The Company uses only credit agreement participants to hedge with, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post collateral when Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.

In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member under CRP’s credit facility as referenced above.

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Note 8—Fair Value Measurements

Recurring Fair Value Measurements

The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

•	Level 1:  Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•	Level 2:  Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.

•	Level 3:  Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.

The following table presents, for each applicable level within the fair value hierarchy, the Company’s net derivative assets and liabilities, including both current and noncurrent portions, measured at fair value on a recurring basis:

(in thousands)	Level 1				Level 2				Level 3
June 30, 2020
Total assets	$	—			$	—			$	—
Total liabilities	—				31,740				—
December 31, 2019
Total assets	$	—			$	—			$	—
Total liabilities	—				325				—

Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy 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 in its entirety requires judgment and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.

Derivatives

The Company uses Level 2 inputs to measure the fair value of its oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. Refer to Note 7—Derivative Instruments for details of the gross and net derivatives assets, liabilities and offset amounts presented in the Consolidated Balance Sheets.

Nonrecurring Fair Value Measurements

The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.

Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. The significant decrease in the forward price curves for crude oil and natural gas in March of 2020 resulted in a triggering event which required the Company to reassess its proved oil and natural gas properties for impairment as of March 31, 2020. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.

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The Company calculates the estimated fair values of its oil and natural gas properties using an income approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management.

The impairment test performed by the Company indicated that a proved property impairment had occurred with respect to certain of its oil and gas fields, and therefore a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value was recorded. Proved oil and natural gas properties with a previous carrying value of $771.4 million were partially written down to their fair value of $179.6 million, resulting in a non-cash impairment charge of $591.8 million being recorded in the first quarter of 2020. All of the Company’s proved oil and gas properties were included in the impairment assessment performed as of March 31, 2020. Two of the Company’s fields were subject to an impairment write-down as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30% to over 100%. There were no triggering event identified as of June 30, 2020 or 2019 and therefore the Company did not recognize any impairment write-downs with respect to its proved property for the three months ended June 30, 2020 and for the three and six months ended June 30, 2019. Impairment expense for proved properties is presented as part of Impairment and Abandonment Expense in the Consolidated Statements of Operations.

Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.

Senior Secured Notes. The Company’s Senior Secured Notes were measured and recorded at their fair value on the date of issuance equal to 83.44% of par. The fair value was determined utilizing the Black-Derman-Toy binomial lattice model, which is a one-factor binomial lattice model that determines the future evolution of the relevant yields. For each node on the lattice, it is determined whether it is preferable to redeem, or not, based on the yields. The model utilizes both a yield curve and a yield volatility as of the valuation date, both of which are estimated based on yields of comparable debt instruments and are inputs that are not observable for the Senior Secured Notes for the term of the debt instrument (a Level 3 classification in the fair value hierarchy). The fair value was measured by the model using the following inputs: (i) the treasury yield curve as of the valuation date, (ii) 12% credit spread, (iii) 45% yield volatility, and (iv) a corporate credit rating of B. The Company has not elected the fair value option, which would require remeasurement at fair value each period, to account for this debt instrument.

Other Financial Instruments

The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.

The Company’s Senior Notes and borrowings under its credit agreement are accounted for at cost, and the cost basis of the Company’s Senior Secured Notes issued in the Debt Exchange was measured based on their fair value on the date of the exchange, as discussed above. The following table summarizes the carrying values, principal amounts and fair values of these instruments as of the dates indicated:

		June 30, 2020												December 31, 2019
		Carrying Value				Principal Amount				Fair Value				Carrying Value				Principal Amount				Fair value
Credit facility due 2023(1)		$	370,000			$	370,000			$	370,000			$	175,000			$	175,000			$	175,000
8.00% Senior Secured Notes due 2025(2)		102,109				127,073				108,012				—				—				—
5.375% Senior Notes due 2026(2)		284,485				289,448				144,724				392,623				400,000				394,480
6.875% Senior Notes due 2027(2)		349,449				356,351				178,176				489,766				500,000				520,000

(1)	The carrying values of the amounts outstanding under CRP’s credit agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.

(2)	The carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the Consolidated Balance Sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the Senior Notes outstanding.

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Note 9—Earnings Per Share

Basic earnings per share (“EPS”) is calculated by dividing net income available to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Diluted EPS is calculated by dividing adjusted net income available to Class A Common Stock by the weighted average shares of diluted Class A Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested restricted stock and performance stock units, outstanding stock options, withholding amounts from employee stock purchase plan and warrants using the treasury stock method, and (ii) the Company’s Class C Common Stock outstanding prior to the Conversion using the “if-converted” method, which is net of tax.

The following table reflects the allocation of net income to common shareholders and EPS computations for the periods indicated based on a weighted average number of common shares outstanding for the period:

	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands, except per share data)	2020				2019				2020				2019
Net income (loss) attributable to Class A Common Stock	$	5,330			$	17,877			$	(542,653	)		$	9,765
Add: Income from conversion of Class C Common Stock	—				735				—				442
Adjusted net income (loss) attributable to Class A Common Stock	$	5,330			$	18,612			$	(542,653	)		$	10,207
Basic weighted average shares of Class A Common Stock outstanding	277,133				264,378				276,543				264,397
Add: Dilutive effects of potential common stock	75				14				—				15
Add: Dilutive effects of conversion of Class C Common Stock	—				12,003				—				12,003
Diluted weighted average shares of Class A Common Stock outstanding	277,208				276,395				276,543				276,415
Basic net earnings (loss) per share of Class A Common Stock	$	0.02			$	0.07			$	(1.96	)		$	0.04
Diluted net earnings (loss) per share of Class A Common Stock	$	0.02			$	0.07			$	(1.96	)		$	0.04

The Company recognized a net loss during the six months ended June 30, 2020. As a result, all potential common shares were anti-dilutive and were excluded from the calculation of diluted net earnings per share. The following table presents shares excluded from the diluted earnings per share calculation for the periods presented as their impact was anti-dilutive:

	Three Months Ended June 30,						Six Months Ended June 30,
(in thousands)	2020			2019			2020			2019
Out-of-the-money stock options	4,696			4,667			4,756			4,612
Restricted stock	5,066			1,758			5,125			1,629
Employee Stock Purchase Plan	—			—			139			—
Weighted average shares of Class C Common Stock	11			—			523			—
Warrants	8,000			8,000			8,000			8,000

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Note 10—Transactions with Related Parties

Riverstone and its affiliates (“Riverstone”) beneficially own a more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the terms of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties. The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as presented in the Consolidated Statements of Operations for the periods indicated as well as the related net receivables outstanding as of the balance sheet dates:

	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands)	2020				2019				2020				2019
Oil and gas sales	$	574			$	1,189			$	1,662			$	1,796
Gathering, processing and transportation expenses	1,109				609				2,062				926

(in thousands)	June 30, 2020				December 31, 2019
Receivable from (payable to) Lucid(1)	$	(367	)		$	91

⁽¹⁾ Represents amounts due from or payable to Lucid and are presented net of unpaid processing fees as of the indicated period end date.

Senior Secured Notes

Note 11—Commitments and Contingencies

Commitments

The Company routinely enters into, extends or amends operating agreements in the ordinary course of business. During the six months ended June 30, 2020, the Company amended one of its firm crude oil sales agreements, which moved the start date of its physical delivery commitments of 30,000 Bbls/d from 2020 to January 1, 2021, and affirmed May 31, 2025 as the end of the initial term of the agreement. There has been no other material, non-routine changes in commitments during the six months ended June 30, 2020. Please refer to Note 13—Commitments and Contingencies included in Part II, Item 8 in the Company’s 2019 Annual Report.

Contingencies

The Company may at times be subject to various commercial or regulatory claims, litigation or other legal proceedings that arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with certainty, management believes it is remote that the impact of such matters that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations, or cash flows. Management is unaware of any pending litigation brought against the Company requiring a contingent liability to be recognized as of the date of these consolidated financial statements.

Note 12—Revenues

Revenue from Contracts with Customers

Crude oil, natural gas and NGL sales are recognized at the point that control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized prices of oil, natural gas, and NGLs fluctuate to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.

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Oil and gas revenues presented within the Consolidated Statements of Operations relate to the sale of oil, natural gas and NGLs as shown below:

	Three Months Ended June 30,								Six Months Ended June 30,
	2020				2019				2020				2019
Operating revenues (in thousands):
Oil sales	$	73,100			$	214,305			$	243,605			$	389,859
Natural gas sales	8,787				8,088				17,145				20,585
NGL sales	8,622				21,846				22,528				48,364
Oil and gas sales	$	90,509			$	244,239			$	283,278			$	458,808

Oil sales

The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.

Natural gas and NGL sales

Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream processing entity at the inlet of the gas plant processing system. The midstream processing entity gathers and processes the raw gas and then remits proceeds to Centennial for the resulting sales of NGLs, while the Company generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the Consolidated Statements of Operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.

Performance obligations

For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At such time, the volumes delivered and sales prices can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the Consolidated Balance Sheets. As of June 30, 2020 and December 31, 2019, such receivable balances were $41.5 million and $76.6 million, respectively.

The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the six months ended June 30, 2020 and 2019, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not material.

Transaction price allocated to remaining performance obligations

Note 13—Leases

At contract inception, the Company determines whether or not an arrangement contains a lease. However, in connection with the implementation of ASC Topic 842, Leases (“ASC 842”), this assessment was made as of the adoption date of ASC 842. Upon determination of a lease, a lease right-of-use (“ROU”) asset and related liability are recorded based on the present value of the future lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease.

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The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. As of June 30, 2020, these leases have remaining lease terms ranging from two months to two years, some of which include options to extend the lease term for up to five years, and some of which include options to early terminate. These options are considered in determining the lease term and are included in the present value of future payments that are recorded for leases when the Company is reasonably certain to exercise the option. Leases with an initial term of one year or less are not recorded in the Consolidated Balance Sheets. Additionally, none of the Company’s lease agreements contain any material residual value guarantees or material restrictive covenants.

The present value of future lease payments is determined at the lease commencement date based upon the Company’s incremental borrowing rate. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s specific risk and the specific lease term. The table below summarizes the Company’s weighted-average discount rate and weighted-average remaining lease term as of the period presented.

		As of June 30, 2020
Weighted-average discount rate		4.76	%
Weighted-average remaining lease term (years)		1.45

The Company’s drilling rig contracts, office rental agreements, and wellhead equipment agreements contain both lease and non-lease components, which are combined and accounted for as a single lease component.

Variable lease payments are recognized in the period in which they are incurred and include operating expenses related to the office rental agreements and expenses incurred on the drilling rig contracts in excess of the contractual rate. Expenses related to short-term leases are recognized on a straight-line basis over the lease term. The following table presents the various components of the Company’s lease expenses for the periods presented.

	Three Months Ended June 30,								Six Months Ended June 30,
(in thousands)	2020				2019				2020				2019
Lease costs(1)
Operating lease cost	$	1,595			$	10,806			$	6,271			$	21,393
Variable lease cost	3,669				703				5,021				1,504
Short-term lease cost(2)	12,217				16,684				31,827				28,908
Total lease cost	$	17,481			$	28,193			$	43,119			$	51,805

(1)

The majority of the Company’s operating leases relate to the operations, drilling or completion of the Company’s wells. Therefore, the lease costs presented in the above table represent the total gross costs the Company incurs, which are not comparable to the Company’s net costs recorded to the Consolidated Statements of Operations, Consolidated Statements of Cash Flows or capitalized in the Consolidated Balance Sheets, as amounts therein are reflected net of amounts billed to the Company’s working interest partners.

(2)	Includes drilling rig lease costs of $4.6 million and $15.8 million for the three and six months ended June 30, 2020, which may not necessarily be recurring in these amounts in the near-term based on the Company’s reduction in its drilling plan.

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Maturities of the Company’s long-term operating lease liabilities by fiscal year as of June 30, 2020 are as follows:

(in thousands)	Total(2)
2020(1)	$	2,211
2021	3,178
2022	425
Total lease payments	5,814
Less: imputed interest	(440		)
Present value of lease liabilities (3)	$	5,374

(1)	Excludes payments made during the six months ended June 30, 2020.

(2)	Total lease payments exclude variable lease payments which can be charged under the terms of the lease agreements.

(3)	Of the total present value of lease liabilities, $3.6 million was recorded to current Operating lease liabilities and $1.8 million was recorded in noncurrent Operating lease liabilities in the Consolidated Balance Sheets as of June 30, 2020.

Note 14—Subsequent Events

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(1)	Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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(1)	Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.

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(1)	These crude oil swap transactions are settled based on the NYMEX WTI or ICE Brent oil price on each trading day within the specified monthly settlement period.

(2)	These oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable settlement period.

(3)	These crude oil collars are settled based on the NYMEX WTI price on each trading day within the specified monthly settlement period and establish floor and ceiling prices for the contractual volumes.

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(1)	These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period.

(2)	These natural gas basis swap contracts are settled based on the difference between the Inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable settlement period.

(1)	At inception, new derivative contracts entered into by us have no intrinsic value.

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•	the actual prices we receive for oil, natural gas and NGLs;

•	the actual development and production expenditures;

•	the amount and timing of actual production; and

•	changes in governmental regulations or taxation.

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