10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q

(Mark One)

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2020

OR

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission file number 001-38435

HighPoint Resources Corporation

(Exact name of registrant as specified in its charter)

Delaware	82-3620361
(State or other jurisdiction of incorporation or organization)	(IRS Employer Identification No.)

555 17th Street, Suite 3700

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 293-9100

(Registrant’s telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:
Title of each class	Trading Symbol	Name of each exchange on which registered
Common stock, $0.001 par value	HPR	New York Stock Exchange

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    ☑  Yes    ☐  No

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    ☑  Yes    ☐  No

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer	☐	Accelerated filer	☑
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    ☐  Yes    ☑  No

There were 215,264,180 shares of $0.001 par value common stock outstanding on July 20, 2020.

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	3
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	24
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	40
Item 4.	Controls and Procedures	41
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	45
Item 3.	Defaults Upon Senior Securities	45
Item 4.	Mine Safety Disclosures	45
Item 5.	Other Information	45
Item 6.	Exhibits	45
SIGNATURES		47

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	June 30, 2020		December 31, 2019
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	2,736	$	16,449
Accounts receivable, net of allowance	59,277		62,120
Derivative assets	72,236		3,916
Prepayments and other current assets	5,962		3,952
Total current assets	140,211		86,437
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,749,042		2,644,129
Unproved oil and gas properties, excluded from amortization	243,309		357,793
Furniture, equipment and other	30,739		29,804
	3,023,090		3,031,726
Accumulated depreciation, depletion, amortization and impairment	(2,235,234)		(967,552)
Total property and equipment, net	787,856		2,064,174
Derivative assets	15,546		—
Other noncurrent assets	8,375		5,441
Total	$	951,988	$	2,156,052
Liabilities and Stockholders’ Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	42,077	$	71,638
Amounts payable to oil and gas property owners	25,226		37,922
Production taxes payable	46,985		61,507
Derivative liabilities	—		4,411
Total current liabilities	114,288		175,478
Long-term debt, net of debt issuance costs	794,673		758,911
Asset retirement obligations	23,950		23,491
Deferred income taxes	2,137		97,418
Other noncurrent liabilities	14,761		17,436
Commitments and contingencies (Note 11)
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 400,000,000 shares; 215,409,996 and 213,669,597 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively, with 3,168,704 and 2,968,497 shares subject to restrictions, respectively	212		211
Additional paid-in capital	1,779,906		1,777,779
Retained earnings (accumulated deficit)	(1,777,939)		(694,672)
Treasury stock, at cost: zero shares at June 30, 2020 and December 31, 2019	—		—
Total stockholders’ equity	2,179		1,083,318
Total	$	951,988	$	2,156,052

See notes to Unaudited Consolidated Financial Statements.

3

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production	$	43,300	$	107,486	$	122,866	$	209,191
Other operating revenues, net	—		98		—		373
Total operating revenues	43,300		107,584		122,866		209,564
Operating Expenses:
Lease operating expense	9,074		10,772		20,155		22,049
Gathering, transportation and processing expense	4,254		1,742		8,666		3,465
Production tax expense	1,449		8,905		(1,059)		12,798
Exploration expense	21		12		52		37
Impairment and abandonment expense	810		995		1,266,236		1,317
(Gain) loss on sale of properties	4,779		2,906		4,779		2,901
Depreciation, depletion and amortization	24,908		72,612		99,833		145,222
Unused commitments	4,378		4,352		8,836		8,821
General and administrative expense	12,890		12,401		23,105		25,061
Merger transaction expense	—		—		—		2,414
Other operating expenses, net	(557)		4		(502)		(20)
Total operating expenses	62,006		114,701		1,430,101		224,065
Operating Income (Loss)	(18,706)		(7,117)		(1,307,235)		(14,501)
Other Income and Expense:
Interest and other income (expense)	259		154		64		468
Interest expense	(15,388)		(14,381)		(29,771)		(28,060)
Commodity derivative gain (loss)	(33,793)		19,544		158,395		(85,647)
Total other income and expense	(48,922)		5,317		128,688		(113,239)
Income (Loss) before Income Taxes	(67,628)		(1,800)		(1,178,547)		(127,740)
(Provision for) Benefit from Income Taxes	—		(110)		95,280		29,601
Net Income (Loss)	$	(67,628)	$	(1,910)	$	(1,083,267)	$	(98,139)
Net Income (Loss) Per Common Share, Basic	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Net Income (Loss) Per Common Share, Diluted	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Weighted Average Common Shares Outstanding, Basic	211,894,790		210,377,152		211,503,310		210,155,678
Weighted Average Common Shares Outstanding, Diluted	211,894,790		210,377,152		211,503,310		210,155,678

See notes to Unaudited Consolidated Financial Statements.

4

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(1,083,267)	$	(98,139)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	99,833		145,222
Deferred income taxes	(95,280)		(29,601)
Impairment and abandonment expense	1,266,236		1,317
Commodity derivative (gain) loss	(158,395)		85,647
Settlements of commodity derivatives	69,447		3,656
Stock compensation and other non-cash charges	2,645		6,980
Amortization of deferred financing costs	2,287		1,275
(Gain) loss on sale of properties	4,779		2,901
Change in operating assets and liabilities:
Accounts receivable	(2,413)		18,475
Prepayments and other assets	(1,905)		(1,463)
Accounts payable, accrued and other liabilities	(16,441)		(6,733)
Amounts payable to oil and gas property owners	(12,696)		(22,923)
Production taxes payable	(14,522)		(8,069)
Net cash provided by (used in) operating activities	60,308		98,545
Investing Activities:
Additions to oil and gas properties, including acquisitions	(110,841)		(258,153)
Additions of furniture, equipment and other	(653)		(3,574)
Other investing activities	3,189		(98)
Net cash provided by (used in) investing activities	(108,305)		(261,825)
Financing Activities:
Proceeds from debt	120,000		150,000
Principal payments on debt	(85,000)		(1,859)
Other financing activities	(716)		(1,523)
Net cash provided by (used in) financing activities	34,284		146,618
Increase (Decrease) in Cash and Cash Equivalents	(13,713)		(16,662)
Beginning Cash and Cash Equivalents	16,449		32,774
Ending Cash and Cash Equivalents	$	2,736	$	16,112

See notes to Unaudited Consolidated Financial Statements.

5

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(UNAUDITED)

(In thousands)

	Three Months Ended June 30, 2020 and 2019
	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Treasury Stock		Total Stockholders’ Equity
Balance at March 31, 2020	$	212	$	1,778,571	$	(1,710,311)	$	—	$	68,472
Restricted stock activity and shares exchanged for tax withholding	—		—		—		(18)		(18)
Stock-based compensation	—		1,353		—		—		1,353
Retirement of treasury stock	—		(18)		—		18		—
Net income (loss)	—		—		(67,628)		—		(67,628)
Balance at June 30, 2020	$	212	$	1,779,906	$	(1,777,939)	$	—	$	2,179
Balance at March 31, 2019	$	210	$	1,772,336	$	(656,071)	$	—	$	1,116,475
Restricted stock activity and shares exchanged for tax withholding	—		—		—		(22)		(22)
Stock-based compensation	—		1,850		—		—		1,850
Retirement of treasury stock	—		(22)		—		22		—
Net income (loss)	—		—		(1,910)		—		(1,910)
Balance at June 30, 2019	$	210	$	1,774,164	$	(657,981)	$	—	$	1,116,393
	Six Months Ended June 30, 2020 and 2019
	Common Stock		Additional Paid-In Capital		Retained Earnings (Accumulated Deficit)		Treasury Stock		Total Stockholders’ Equity
Balance at December 31, 2019	$	211	$	1,777,779	$	(694,672)	$	—	$	1,083,318
Restricted stock activity and shares exchanged for tax withholding	1		—		—		(654)		(653)
Stock-based compensation	—		2,781		—		—		2,781
Retirement of treasury stock	—		(654)		—		654		—
Net income (loss)	—		—		(1,083,267)		—		(1,083,267)
Balance at June 30, 2020	$	212	$	1,779,906	$	(1,777,939)	$	—	$	2,179
Balance at December 31, 2018	$	210	$	1,771,730	$	(559,842)	$	—	$	1,212,098
Restricted stock activity and shares exchanged for tax withholding	—		—		—		(1,506)		(1,506)
Stock-based compensation	—		3,940		—		—		3,940
Retirement of treasury stock	—		(1,506)		—		1,506		—
Net income (loss)	—		—		(98,139)		—		(98,139)
Balance at June 30, 2019	$	210	$	1,774,164	$	(657,981)	$	—	$	1,116,393

See notes to Unaudited Consolidated Financial Statements.

6

HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

June 30, 2020

1. Organization

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”), is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”). The Company became the successor to Bill Barrett Corporation (“Bill Barrett”), on March 19, 2018, upon closing of the transactions contemplated by the Agreement and Plan of Merger, dated December 4, 2017 (the “Merger Agreement”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC (“Fifth Creek”) (the “Merger”). As a result of the Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. The Company currently conducts its activities principally in the Denver Julesburg Basin (“DJ Basin”) in Colorado. Except where the context indicates otherwise, references herein to the “Company” with respect to periods prior to the completion of the Merger refer to Bill Barrett and its subsidiaries.

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company’s Annual Report on Form 10-K for the year ended December 31, 2019 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. 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 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure 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 initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, right-of-use assets and lease liabilities, deferred income taxes, the timing of dry hole costs, impairments of proved and unproved oil and gas properties and fair values of derivative instruments and stock-based payment awards. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.

Accounts Receivable. Accounts receivable is comprised of the following:

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	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Oil, gas and NGL sales	$	32,383	$	50,171
Due from joint interest owners (1)	23,796		9,551
Other	3,129		2,419
Allowance for doubtful accounts	(31)		(21)
Total accounts receivable	$	59,277	$	62,120

(1)Includes $12.9 million associated with one joint interest partner. In the event of nonpayment, the Company expects to net the outstanding amount against certain revenues payable to this joint interest partner.

Oil and Gas Properties. The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Proved properties	$	721,174	$	725,964
Wells and related equipment and facilities	1,910,527		1,805,136
Support equipment and facilities	105,397		99,540
Materials and supplies	11,944		13,489
Total proved oil and gas properties	$	2,749,042	$	2,644,129
Unproved properties	182,605		265,387
Wells and facilities in progress	60,704		92,406
Total unproved oil and gas properties, excluded from amortization	$	243,309	$	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,224,428)		(958,475)
Total oil and gas properties, net	$	767,923	$	2,043,447

The Company reviews proved oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on an analysis of quantitative and qualitative factors existing as of the balance sheet date including the Company’s development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, income taxes and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, the Organization of Petroleum Exporting Countries (“OPEC”), along with non-OPEC oil-producing countries (collectively known as “OPEC+”), initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of $30.45 per barrel for the month of March 2020, compared to an average of $59.80 per barrel for the month of December 2019. These events led to a decline in the recoverability of the carrying value of the Company’s oil and gas properties during the three months ended March 31, 2020. Since the carrying amount of the oil and gas properties was no longer recoverable, the Company impaired the carrying value to fair value. Therefore, the Company recognized non-cash impairment

8

charges during the three months ended March 31, 2020, which were included within impairment and abandonment expense in the Unaudited Consolidated Statements of Operations.

For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company’s determination of fair value associated with the Company’s proved and unproved oil and gas properties. Through the use of the Company’s production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the proved developed producing (“PDP”) and proved developed non-producing (“PDN”) reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the proved undeveloped (“PUD”), probable (“PROB”) and possible (“POSS”) reserves. The Company’s impairment and abandonment expense for the three and six months ended June 30, 2020 and 2019 is summarized below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Impairment of proved oil and gas properties	$	—	$	—	$	1,188,566	$	—
Impairment of unproved oil and gas properties	—		—		76,298		—
Abandonment expense	810		995		1,372		1,317
Total impairment and abandonment expense	$	810	$	995	$	1,266,236	$	1,317

Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Accrued drilling, completion and facility costs	$	12,957	$	25,667
Accrued lease operating, gathering, transportation and processing expenses	7,364		8,046
Accrued general and administrative expenses	6,910		6,612
Accrued interest payable	6,681		6,832
Trade payables	3,951		17,488
Operating lease liability	1,954		1,287
Other	2,260		5,706
Total accounts payable and accrued liabilities	$	42,077	$	71,638

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Under Wyoming law, the Company is exposed to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. When such third parties are unable to fulfill their contractual obligations to the Company as provided for in purchase and sale agreements, landowners, as well as the Bureau of Land Management, may demand that the Company perform such activities.

Revenue Recognition. All of the Company’s sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company’s contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company’s contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company’s contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of June 30, 2020, the Company had open contracts with customers with terms of 1 month to 17 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The Company’s contracts with customers typically require payment within one month of delivery.

Under the Company’s contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of

9

these contracts compensate the Company for the value of the residue gas and NGLs at current market prices for each product. The Company’s oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the Company’s oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and therefore are recorded in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by the Company. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances were not significant in the periods presented.

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. A valuation allowance is recorded if it is more likely than not that all or some portion of the Company’s deferred tax assets will not be realized. The Company regularly assesses the realizability of the deferred tax assets considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine if a valuation allowance is required. Changes to the Company’s development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors including changes in tax law could change the valuation allowance in future periods, resulting in recognition of a tax expense or benefit.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of June 30, 2020.

Comprehensive Income. The Company has no elements of other comprehensive income, therefore, the Company’s net income (loss) on the Unaudited Consolidated Statements of Operations represents comprehensive income.

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The Company was in a net loss position for the three and six months ended June 30, 2020 and 2019; therefore, all potentially dilutive securities were anti-dilutive.

The following table sets forth the calculation of basic and diluted income (loss) per share:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)
Net income (loss)	$	(67,628)	$	(1,910)	$	(1,083,267)	$	(98,139)
Basic weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Diluted weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Basic net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Diluted net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)

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New Accounting Pronouncements. In April 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2022, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other affected transactions. The Company currently has only one contract, its credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update has an effective period of March 12, 2020 through December 31, 2022 and allows for elections to be made by the Company in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications for that Topic or Industry Subtopic. The Company does not believe the standard will have a material impact on the Company’s financial statements.

In August 2018, the FASB issued ASU 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments, Credit Losses. The objective of this update is to amend current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”)) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 was effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures and financial statements.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Cash paid for interest	$	27,635	$	26,689
Cash paid for income taxes	—		—
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases	873		595
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)(2)	777		14,955
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties	11,746		87,109
Change in asset retirement obligations, net of disposals	(12)		(5,022)
Retirement of treasury stock	(654)		(1,506)
Properties exchanged in non-cash transactions	4,753		4,561

(1)Excludes the reclassifications of lease incentives and deferred rent balances.

(2)The six months ended June 30, 2019 included $14.0 million of right-of-use assets established with the adoption of ASC 842, Leases, effective January 1, 2019.

4. Long-Term Debt

The Company’s outstanding debt is summarized below:

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		As of June 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Debt Issuance Costs		Carrying Amount		Principal		Debt Issuance Costs		Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	175,000	$	—	$	175,000	$	140,000	$	—	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,954)		348,046		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,373)		271,627		275,000		(3,717)		271,283
Total Long-Term Debt		$	800,000	$	(5,327)	$	794,673	$	765,000	$	(6,089)	$	758,911

Amended Credit Facility

On May 21, 2020, the Company entered into an amendment to the fourth amended and restated credit facility (the “Amended Credit Facility”), which decreased the aggregate elected commitment amount and the borrowing base from $500.0 million to $300.0 million, increased the applicable margins for interest and commitment fee rates and added provisions requiring the availability under the Amended Credit Facility to be at least $50.0 million and the Company’s weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. The Company had $175.0 million and $140.0 million outstanding under the Amended Credit Facility as of June 30, 2020 and December 31, 2019, respectively. As credit support for future payments under a contractual obligation, a $21.7 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity under the Amended Credit Facility as of June 30, 2020 to $53.3 million after taking into account the $50.0 million availability requirement. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if the Company has more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because the Company’s 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

As of May 21, 2020, interest rates on outstanding loans under the Amended Credit Facility are either adjusted LIBOR plus applicable margins of 2.5% to 3.5% or an alternate base rate, which is generally the prime rate, plus applicable margins of 1.5% to 2.5%, and the unused commitment fee is 0.5%. The applicable margins and the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Amended Credit Facility was 2.7% and 4.2% for the three months ended June 30, 2020 and 2019, respectively, and 3.0% and 4.1% for the six months ended June 30, 2020 and 2019, respectively.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from the reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt.

The Company has financial covenants associated with its Amended Credit Facility that are measured each fiscal quarter. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. However, if current market conditions continue, the Company may not be able to maintain compliance with these financial covenants. In particular, the Company may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 2021. Further, if the Company’s independent auditor were to include an explanatory paragraph regarding the Company’s ability to continue as a “going concern” in the auditors’ report on the Company’s financial statements for the year ending December 31, 2020, this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, the Company may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under the Company’s senior notes and the Company may not have other sources of capital to repay the amounts due.

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Senior Notes

The issuer of the 7.0% Senior Notes and the 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett), or Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the Merger, HighPoint Resources Corporation, or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. In addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of the Subsidiary Issuer on August 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. The Company has no additional subsidiaries or non-guarantor subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor. HighPoint Operating Corporation is currently in compliance with all covenants and has complied with all covenants since issuance.

Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

5. Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2020 is as follows (in thousands):

As of December 31, 2019	$	25,709
Liabilities incurred	488
Liabilities settled	(766)
Disposition of properties	(143)
Accretion expense	872
Revisions to estimate	409
As of June 30, 2020	$	26,569
Less: Current asset retirement obligations	2,619
Long-term asset retirement obligations	$	23,950

6. Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance

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sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are measured at fair value on a recurring basis in the Company’s Unaudited Consolidated Balance Sheets. The following methods and assumptions were used to estimate the fair values:

Cash equivalents – The highly liquid cash equivalents are recorded at fair value. Carrying value approximates fair value, which represents a Level 1 input.

Deferred compensation plan – The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets in the Unaudited Consolidated Balance Sheets. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Commodity derivatives – The fair value of crude oil, natural gas and NGL swaps and cashless collars are valued based on an income approach using various assumptions, such as quoted forward prices for commodities and time value factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are, therefore, designated as Level 2 inputs. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. The Company currently utilizes an independent third party to perform the valuation.

The commodity derivatives have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company.

The following tables set forth by level within the fair value hierarchy the Company’s non-financial assets and liabilities that were measured at fair value on a recurring basis in the Unaudited Consolidated Balance Sheets.

	Level 1		Level 2		Level 3		Total
	(in thousands)
As of June 30, 2020
Financial Assets
Deferred compensation plan	$	1,167	$	—	$	—	$	1,167
Commodity derivatives	—		91,150		—		91,150
Financial Liabilities
Commodity derivatives	—		3,368		—		3,368
As of December 31, 2019
Financial Assets
Deferred compensation plan	$	2,033	$	—	$	—	$	2,033
Commodity derivatives	—		8,890		—		8,890
Financial Liabilities
Commodity derivatives	—		10,056		—		10,056

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Oil and gas properties – Proved oil and natural gas properties are evaluated for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever the Company concludes the carrying value may not be recoverable, the Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on its development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation

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deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future net revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the three months ended March 31, 2020, the Company’s proved oil and gas properties with a carrying value of $1.7 billion were reduced to a fair value of $0.5 billion, resulting in an impairment of $1.2 billion which was included in impairment and abandonment expense on the Unaudited Statement of Operations for the three months ended March 31, 2020. For the three months ended March 31, 2020, the Company contracted with an independent third party to assist with the Company’s determination of fair value associated with its proved oil and gas properties. Through the use of the Company’s production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the PDP and PDN reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the PUD reserves. The following table includes quantitative information about the significant unobservable inputs, categorized within Level 3 of the fair value hierarchy, that were used in the fair value measurement.

Level 3 Unobservable Inputs	As of March 31, 2020
Price (1)
Oil (per Bbl)	$29 to $60
Gas (per MMbtu)	$2.03 to $2.52
NGL (percentage of oil price)	24% to 31%
Reserve adjustment factors
PDP	100%
PDN	95%
Discount rate	11%

(1)These prices were adjusted for location and quality differentials.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. During the three months ended March 31, 2020, due to substantial commodity price declines, certain unproved oil and gas properties with a carrying value of $256.0 million were reduced to a fair value of $179.7 million, resulting in an impairment of $76.3 million which was included in impairment and abandonment expense on the Unaudited Statement of Operations for the three months ended March 31, 2020. For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company’s determination of fair value of the Company’s unproved oil and gas properties. The third party used the market approach utilizing sales prices of comparable properties to determine the fair value of the unproved oil and gas properties.

Additional Fair Value Disclosures

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The estimated fair value of the 7.0% Senior Notes was approximately $286.1 million and $335.0 million as of June 30, 2020 and December 31, 2019, respectively. The estimated fair value of the 8.75% Senior Notes was approximately $147.1 million and $251.2 million as of June 30, 2020 and December 31, 2019, respectively. The fair values of the Company’s fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility. The recorded value of the Amended Credit Facility is not materially different from its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company’s borrowing base utilization. The Amended Credit Facility had a balance of $175.0 million as of June 30, 2020 and $140.0 million as of December 31, 2019. The fair value measurements for the Amended Credit Facility represent Level 2 inputs.

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7. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and swaption contracts related to the sale of a portion of the Company’s production. A swap allows the Company to receive a fixed price for its production and pay a variable market price to the counterparty. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. The Company has also entered into crude oil swaps to fix the differential in pricing between the NYMEX WTI calendar month average and the physical crude delivery month (“oil roll swaps”). The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included on the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented on the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of June 30, 2020
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	73,466	$	(1,230)	$	72,236
Derivative assets (noncurrent)	17,684		(2,138)		15,546
Total derivative assets	$	91,150	$	(3,368)	$	87,782
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(1,230)	$	1,230	$	—
Other noncurrent liabilities	(2,138)		2,138		—
Total derivative liabilities	$	(3,368)	$	3,368	$	—
	As of December 31, 2019
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	8,477	$	(4,561)	$	3,916
Derivative assets (noncurrent)	413		(413)		—
Total derivative assets	$	8,890	$	(4,974)	$	3,916
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(8,972)	$	4,561	$	(4,411)
Other noncurrent liabilities	(1,084)		413		(671)
Total derivative liabilities	$	(10,056)	$	4,974	$	(5,082)

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(1)Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

As of June 30, 2020, the Company had swap and swaption contracts in place to hedge the following volumes for the periods indicated:

	July – December 2020			For the year 2021			For the year 2022
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps
Oil (Bbls)	2,760,000	$	56.59	3,098,000	$	54.30	—	$	—
Natural Gas (MMbtu)	3,680,000	$	1.83	5,790,000	$	2.13	—	$	—
Oil Roll Swaps (1)
Oil (Bbls)	276,500	$	(1.47)	—	—		—	—
Swaptions
Oil (Bbls)	—	$	—	—	$	—	1,092,000	$	55.08

(1)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

The Company’s derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with eight different counterparties as of June 30, 2020. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, the Company may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

8. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and six months ended June 30, 2020 and 2019, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and six months ended June 30, 2020 and 2019.

Income tax benefit for the three and six months ended June 30, 2020 and 2019 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation, state income taxes, and for 2020, the

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effect of deferred tax asset valuation allowances. For the three and six months ended June 30, 2020, the Company recognized zero and $95.3 million of income tax benefit, respectively. For the three and six months ended June 30, 2019, the Company recognized $0.1 million of income tax expense and $29.6 million of income tax benefit, respectively. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. For the three and six months ended June 30, 2020, the Company determined that there would not be sufficient future taxable income to use existing deferred tax assets and has recorded a valuation allowance against the existing net deferred tax assets. For the six months ended June 30, 2020, the Company has recorded a deferred tax liability of $2.1 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. 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 their expiration.

In response to the COVID-19 pandemic, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) on March 27, 2020. Several of the provisions included in the CARES Act apply to the Company. The primary impact is the accelerated refundability of the Company’s $1.4 million income tax receivable related to minimum tax credit carryforwards to 2019. The depreciable lives related to 2018 and 2019 qualified improvement property will be adjusted and result in accelerated tax depreciation. In addition, the CARES Act temporarily suspends the 80% income limitation for net operating losses generated and utilized in years beginning prior to January 1, 2021.

9. Equity Incentive Compensation Plans and Other Long-term Incentive Programs

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period). Nonvested shares of common stock generally vest ratably over a three year service period, and nonvested shares of common stock units vest over a one year service period. Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period). Cash-based awards generally have a cliff vest of three years.

The following table presents the long-term equity and cash incentive compensation related to awards for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Nonvested common stock (1)	$	1,150	$	1,533	$	2,300	$	3,329
Nonvested common stock units (1)	202		318		482		612
Nonvested performance cash units (2)(3)	198		445		(776)		1,077
Total	$	1,550	$	2,296	$	2,006	$	5,018

(1)Unrecognized compensation expense as of June 30, 2020 was $5.1 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.8 years.

(2)The nonvested performance-based cash units are accounted for as liability awards with $0.3 million and $1.2 million in other noncurrent liabilities as of June 30, 2020 and December 31, 2019, respectively, in the Unaudited Consolidated Balance Sheets.

(3)Liability awards are fair valued at each reporting date. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Nonvested Equity and Cash Awards. The following tables present the equity and cash awards granted pursuant to the Company’s various stock compensation plans. A summary of the Company’s nonvested common stock awards for the three and six months ended June 30, 2020 and 2019 is presented below:

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	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at April 1,	3,531,812	$	2.10	3,431,780	$	3.90
Granted	—	—		6,000	2.66
Vested	(112,677)	4.26		(30,031)	5.81
Forfeited or expired	(250,431)	1.52		(1,615)	7.14
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at January 1,	2,968,497	$	3.81	2,912,166	$	5.27
Granted	2,028,617	1.14		1,841,700	2.64
Vested	(1,568,491)	4.25		(1,329,630)	5.20
Forfeited or expired	(259,919)	1.59		(18,102)	4.96
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88

A summary of the Company’s nonvested common stock unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at April 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		628,380	1.87
Vested	(638,355)	2.63		(143,514)	5.77
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at January 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		643,084	1.88
Vested	(638,355)	2.63		(158,218)	5.44
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27

A summary of the Company’s nonvested performance-based cash unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

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	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at April 1,	6,096,230			2,868,634
Forfeited or expired	(656,430)			—
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at January 1,	2,576,062			909,585
Granted	3,569,434			2,026,521
Forfeited or expired	(705,696)			(67,472)
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82

Performance Cash Program

2020 Program. In February 2020, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the “2020 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2023, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2022, will be the Company’s total shareholder return (“TSR”) based on a matrix measurement of (1) the Company’s absolute performance and (2) the Company’s ranking relative to a defined peer group’s individual TSRs (“Relative TSR”). The Company’s absolute performance is measured against the December 31, 2019 closing share price of $1.69. For the portion of the program based on absolute performance, the payout will be equal to the Company’s absolute TSR up to 100%, which is the maximum payout for this portion. For the portion of the program based on relative performance (i) if the Company’s Relative TSR is less than 30%, the payout is zero and (ii) if the Company’s Relative TSR is 30% or greater, the payout is equal to the Company’s percentile rank up to 100% of the original grant. The Company’s combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant.

10. Leases

A contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. For all leases, other than those that qualify for the short-term recognition exemption, the Company recognizes as of the lease commencement date on the balance sheet a liability for its obligation related to the lease and a corresponding asset representing the Company’s right to use the underlying asset over the period of use. The Company currently has leases for office space and other equipment, all of which are classified as operating leases.

The Company’s leases have remaining terms of up to eight years. Certain lease agreements contain options to extend or early terminate the agreement. These options are used to calculate right-of-use asset and lease liability balances when it is reasonably certain that the Company will exercise these options. The discount rate used to calculate the present value of the future minimum lease payments is the Company’s incremental borrowing rate.

The Company elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the income statement on a straight-line basis over the lease term. The Company also elected, for certain classes of underlying assets, to combine lease and non-lease components. Therefore, the Company elected to combine lease and non-lease components for drilling rig and gathering system asset classes. These assets are not reported on the Unaudited Consolidated Balance Sheets as the Company’s lease contracts for drilling rigs are currently classified as short-term and the Company’s lease contract for a gathering system includes variable payments.

For the three and six months ended June 30, 2020 and 2019, lease cost were as follows:

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	Three Months Ended June 30,				Six Months Ended June 30,
Lease Cost	2020		2019		2020		2019
	(in thousands)
Operating lease cost (1)(3)	$	529	$	569	$	1,039	$	1,117
Short-term lease cost (2)(3)	789		4,167		3,052		10,386
Variable lease cost (4)	373		—		693		—
Total lease cost	$	1,691	$	4,736	$	4,784	$	11,503

(1)Operating lease cost was primarily included in general and administrative expense or lease operating expense on the Unaudited Consolidated Statements of Operations.

(2)Short-term lease cost primarily includes leases for drilling rigs, which were capitalized to property, plant and equipment on the Unaudited Consolidated Balance Sheets.

(3)A portion of the operating lease cost and a majority of the short-term lease cost represent gross amounts that the Company was financially committed to pay. However, the Company recorded in the financial statements its proportionate share based on the Company’s working interest, which varies from property to property.

(4)Variable lease cost is related to a gathering agreement and is included in oil, gas, and NGL production on the Unaudited Consolidated Statements of Operations.

Supplemental balance sheet information related to leases as of June 30, 2020 and December 31, 2019, were as follows:

Operating Leases	As of June 30, 2020			As of December 31, 2019
	(in thousands)
Right-of-use assets (1)	$	9,906		$	9,287
Accumulated amortization (2)	(1,621)			(1,142)
Total right-of-use assets, net (3)	$	8,285		$	8,145
Current lease liabilities (4)	(1,954)			(1,287)
Noncurrent lease liabilities (5)	(12,834)			(13,195)
Total lease liabilities (3)	$	(14,788)		$	(14,482)
Weighted average remaining lease term
Operating leases (in years)	7.3			7.8
Weighted average discount rate
Operating leases	5.6		%	5.6		%

(1)Included in furniture, equipment and other in the Unaudited Consolidated Balance Sheets.

(2)Included in accumulated depreciation, depletion, amortization and impairment in the Unaudited Consolidated Balance Sheets.

(3)The difference between the right-of-use assets and total lease liabilities is primarily related to lease incentives and deferred rent balances, which were required to be netted against the right-of-use assets as of the ASC 842 implementation date of January 1, 2019.

(4)Included in accounts payable and accrued liabilities in the Unaudited Consolidated Balance Sheets.

(5)Included in other noncurrent liabilities in the Unaudited Consolidated Balance Sheets.

Maturities of lease liabilities as of June 30, 2020 and December 31, 2019 were as follows:

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	As of June 30, 2020		As of December 31, 2019
	(in thousands)
2020	$	1,377	$	2,056
2021	2,635		2,355
2022	2,324		2,044
2023	2,101		2,024
2024	2,078		2,078
Thereafter	7,576		7,577
Total	$	18,091	$	18,134
Less: Interest	(3,303)		(3,652)
Present value of lease liabilities	$	14,788	$	14,482

11. Commitments and Contingencies

Firm Transportation Agreements. The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.

The Company is party to one firm pipeline transportation contract to provide capacity on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges from May 2020 through April 2025 regardless of the amount of pipeline capacity utilized by the Company.

The amounts in the table below represent the Company’s future minimum transportation charges:

	As of June 30, 2020
	(in thousands)
2020	$	12,732
2021	19,777
2022	13,064
2023	14,600
2024	14,640
Thereafter	4,800
Total	$	79,613

Gas Gathering and Processing Agreements. The Company is party to one minimum volume commitment and two reimbursement obligations. The minimum volume commitment requires the Company to deliver a minimum volume of natural gas to a midstream entity for gathering and processing. The contract requires the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The reimbursement obligations require the Company to pay monthly gathering and processing fees per Mcf of production to reimburse midstream entities for their costs to construct gas gathering and processing facilities. If the costs are not reimbursed by the Company via the monthly gathering and processing fees, the Company must pay the difference. The amounts in the table below represent the Company’s future minimum charges under both types of agreements:

	As of June 30, 2020
	(in thousands)
2020	$	1,089
2021	5,268
Thereafter	—
Total	$	6,357

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Other Commitments. The Company has one drilling commitment with a joint interest partner that requires the Company to drill and complete two wells by July 2022 and three wells by July 2023. If the drilling commitment is not met, the Company must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. The Company is party to two minimum volume commitments for fresh water. The minimum volume commitments require the Company to purchase a minimum volume of fresh water from a water supplier. The contracts require the Company pay a fee associated with the contracted volumes regardless of the amount delivered. The Company also has non-cancellable agreements for information technology services. Future minimum annual payments under these agreements are as follows:

	As of June 30, 2020
	(in thousands)
2020	$	1,098
2021	1,285
2022 (1)	11,485
2023 (1)	16,285
Thereafter	—
Total	$	30,153

(1)Includes $10.2 million in 2022 and $15.3 million in 2023 related to a drilling commitment.

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its Unaudited Consolidated Balance Sheet, Cash Flows or Statements of Operations, other than the following.

Sterling Energy Investments LLC v. HighPoint Operating Corporation, 2020CV32034, District Court in Denver, Colorado. On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint Operating Corporation, a subsidiary of the Company, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017, by and between HighPoint Operating Corporation and Sterling. Sterling alleges that HighPoint Operating Corporation breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. The Company vigorously denies Sterling’s claims. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, the Company filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Gathering Agreement. The Company is seeking monetary damages in an amount not yet specified.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

This Quarterly Report on Form 10-Q contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements as to future plans, estimates, beliefs and expected performance of HighPoint Resources Corporation. Forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, risks and uncertainties relating to:

•outbreaks of communicable diseases like COVID-19 and resulting regulatory and economic consequences;

•the ability and willingness of members of the Organization of Petroleum Exporting Countries (“OPEC”) along with non-OPEC oil-producing countries (collectively known as “OPEC+”), to agree to and maintain oil price and production controls;

•ability to regain compliance with the minimum share price requirement under the New York Stock Exchange (the “NYSE”) continued listing requirements and avert delisting of our common stock;

•debt and equity market conditions and availability of capital;

•reductions in the borrowing base under our amended revolving credit facility (the “Amended Credit Facility”);

•any failure to comply with the financial or other covenants under our Amended Credit Facility, which could result in an event of default that could raise substantial doubt about our ability to continue as a going concern;

•downstream shut-ins due to oversupply and shortage of storage capacity;

•legislative, judicial or regulatory changes including initiatives to impose increased setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and initiatives related to drilling and completion techniques such as hydraulic fracturing;

•potential failure to achieve expected production from existing and future exploration or development projects or acquisitions;

•volatility of market prices received for oil, natural gas and natural gas liquids (“NGLs”), and the risk of a prolonged period of depressed prices;

•declines in the values of our oil and natural gas properties resulting in impairments;

•reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by the Securities and Exchange Commission;

•derivative and hedging activities;

•the concentration of our properties in the Rocky Mountain region;

•compliance with environmental and other regulations;

•economic and competitive conditions;

•occurrence of property divestitures or acquisitions;

•costs and availability of third party facilities for gathering, processing, refining and transportation;

•future processing volumes and pipeline throughput;

•impact of health and safety issues on operations;

•operational risks, including the risk of industrial accidents and natural disasters;

•ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way;

•higher than expected costs and expenses including production, drilling and well equipment costs;

•changes in estimates of proved reserves;

•the potential for production decline rates from our wells, and/or drilling and related costs, to be greater than we expect;

•ability to replace natural production declines with acquisitions, new drilling or recompletion activities;

•exploration risks such as the risk of drilling unsuccessful wells;

•capital expenditures and contractual obligations;

•liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;

•midstream capacity issues;

•changes in tax laws and statutory tax rates; and

•other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2019 under the headings “Cautionary Note Regarding Forward-Looking Statements” and “Risk Factors” and in Part II, Item 1A, “Risk Factors” of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

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In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not undertake any obligation to update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

We develop oil and natural gas in the Rocky Mountain region of the United States. We seek to build stockholder value by delivering profitable growth in cash flow, reserves and production through the development of oil and natural gas assets. In order to deliver profitable growth, we allocate capital to our highest return assets, concentrate expenditures on exploiting our core assets, maintain capital discipline and optimize operations while upholding high-level standards for health, safety and the environment. Substantially all of our revenues are generated through the sale of oil and natural gas production and NGL recovery at market prices.

We are committed to developing and producing oil and natural gas in a responsible and safe manner. Our employees work diligently with regulatory agencies, as well as environmental, wildlife and community organizations, to ensure that exploration and development activities meet stakeholders’ expectations and regulatory requirements.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, OPEC+ initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of $30.45 per barrel for the month of March 2020 and $16.70 per barrel for the month of April 2020 before increasing to an average of $38.31 per barrel for the month of June 2020, compared to $59.80 for the month of December 2019. These declines in prices have adversely affected the economics of our existing wells and planned future development, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020.

Aside from the impairment of our proved and unproved oil and gas properties, impacts to our results of operations for the three and six months ended June 30, 2020 from price declines were mitigated by hedges in place on 78% and 86%, respectively, of our oil production. As of July 20, 2020, we have hedged 2,760,000 barrels, or approximately 92%, of our expected remaining 2020 oil production and 3,098,000 barrels of our expected 2021 oil production, at price levels that provide some economic certainty to our cash flows. In addition, we have hedged 3,680,000 MMbtu, or approximately 56%, of our expected remaining 2020 natural gas production, and 5,790,000 MMbtu of our expected 2021 natural gas production. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The substantial decline in oil price has increased the volatility and amplitude of risks we face as described in this report and in our Annual Report on Form 10-K for the year ended December 31, 2019. If oil prices do not improve, capital availability, our liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. There is uncertainty around the timing and recovery of the global economy from COVID-19 and its effects on the supply and demand for crude oil. Therefore, we expect continued volatility and uncertainty in the outlook for near to medium term oil prices.

As of the date of this filing, August 3, 2020, we believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility to meet our obligations and commitments for the next twelve months. We deferred drilling and completion activity starting in May 2020 and will continue to defer until oil prices improve to a level that allows us to meet our target return threshold. In addition, we are currently in compliance with all financial covenants under our Amended Credit Facility and have $71.2 million available for future borrowing. However, if current market conditions continue, we may not be able to maintain compliance with our financial covenants. In particular, we may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 2021. Further, if our independent auditor were to include an explanatory paragraph regarding our ability to continue as a “going concern” in the auditors’ report on our financial statements for the year ending December 31, 2020, this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, we may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful,

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all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under our senior notes and we may not have other sources of capital to repay the amounts due.

We may from time to time seek to retire, purchase or otherwise refinance our outstanding debt securities through cash purchases and/or exchanges, in open market purchases, privately negotiated transactions, exchange offers or otherwise. Any such transactions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

We operate in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of our operations are conducted in the Rocky Mountain region of the United States. Consequently, we currently report a single reportable segment.

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Results of Operations

The following table sets forth selected operating data for the periods indicated:

Three Months Ended June 30, 2020 Compared with Three Months Ended June 30, 2019

	Three Months Ended June 30,				Increase (Decrease)
	2020		2019		Amount		Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	43,300	$	107,486	$	(64,186)	(60)	%
Other operating revenues	—		98		(98)		(100)	%
Total operating revenues	43,300		107,584		(64,284)		(60)	%
Operating Expenses
Lease operating expense	9,074		10,772		(1,698)		(16)	%
Gathering, transportation and processing expense	4,254		1,742		2,512		144	%
Production tax expense	1,449		8,905		(7,456)		(84)	%
Exploration expense	21		12		9		75	%
Impairment, dry hole costs and abandonment expense	810		995		(185)		(19)	%
(Gain) loss on sale of properties	4,779		2,906		1,873		64	%
Depreciation, depletion and amortization	24,908		72,612		(47,704)		(66)	%
Unused commitments	4,378		4,352		26		1	%
General and administrative expense (1)	12,890		12,401		489		4	%
Other operating expense, net	(557)		4		(561)		*nm
Total operating expenses	$	62,006	$	114,701	$	(52,695)	(46)	%
Production Data:
Oil (MBbls)	1,638		1,748		(110)		(6)	%
Natural gas (MMcf)	3,948		3,558		390		11	%
NGLs (MBbls)	575		500		75		15	%
Combined volumes (MBoe)	2,871		2,841		30		1	%
Daily combined volumes (Boe/d)	31,549		31,220		329		1	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	22.74	$	55.46	$	(32.72)	(59)	%
Natural gas (per Mcf)	0.80		1.58		(0.78)		(49)	%
NGLs (per Bbl)	5.07		9.81		(4.74)		(48)	%
Combined (per Boe)	15.08		37.83		(22.75)		(60)	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	47.33	$	54.88	$	(7.55)	(14)	%
Natural gas (per Mcf)	0.88		1.59		(0.71)		(45)	%
NGLs (per Bbl)	5.07		9.81		(4.74)		(48)	%
Combined (per Boe)	29.23		37.48		(8.25)		(22)	%
Average Costs (per Boe):
Lease operating expense	$	3.16	$	3.79	$	(0.63)	(17)	%
Gathering, transportation and processing expense	1.48		0.61		0.87		143	%
Production tax expense	0.50		3.13		(2.63)		(84)	%
Depreciation, depletion and amortization	8.68		25.56		(16.88)		(66)	%
General and administrative expense (1)	4.49		4.37		0.12		3	%

*Not meaningful.

(1)Included in general and administrative expense is long-term cash and equity incentive compensation of $1.6 million (or $0.54 per Boe) and $2.3 million (or $0.81 per Boe) for the three months ended June 30, 2020 and 2019, respectively.

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Production Revenues and Volumes. Production revenues decreased to $43.3 million for the three months ended June 30, 2020 from $107.5 million for the three months ended June 30, 2019. The decrease in production revenues was due to a 60% decrease in average realized prices before hedging, offset by a 1% increase in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $64.6 million, while the increase in production volumes increased production revenues by approximately $0.4 million.

Lease Operating Expense (“LOE”). LOE was $9.1 million for the three months ended June 30, 2020 and $10.8 million for the three months ended June 30, 2019. LOE decreased to $3.16 per Boe for the three months ended June 30, 2020 from $3.79 per Boe for the three months ended June 30, 2019. We started seeing a decrease in service industry costs during the three months ended June 30, 2020.

Gathering, Transportation and Processing Expense (“GTP”). GTP expense increased to $1.48 per Boe for the three months ended June 30, 2020 from $0.61 per Boe for the three months ended June 30, 2019.

Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred associated with gas and NGLs in the Hereford Field in the DJ Basin, which was acquired in the Merger, are included in GTP expense and costs incurred associated with gas and NGLs in the Northeast Wattenberg Field in the DJ Basin are included in production revenues. Costs incurred associated with oil are included in production revenues for both areas. See the “Revenue Recognition” section in Note 2 for additional information.

The increase in GTP per Boe for the three months ended June 30, 2020 compared to the three months ended June 30, 2019 was due to an increase in our production mix from the Hereford Field under the existing contractual arrangement, which has a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to $1.4 million for the three months ended June 30, 2020 from $8.9 million for the three months ended June 30, 2019. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes for the three months ended June 30, 2020 included Colorado severance tax refunds of $1.8 million based on an audit of tax years 2015 to 2017. Excluding the severance tax refunds associated with tax years 2015 to 2017, production taxes as a percentage of oil, natural gas and NGL sales were 7.5% and 8.3% for the three months ended June 30, 2020 and June 30, 2019, respectively. The decrease in the rate for the three months ended June 30, 2020 was due to a decrease in our ad valorem effective tax rate.

Depreciation, Depletion and Amortization (“DD&A”). DD&A decreased to $24.9 million for the three months ended June 30, 2020 compared with $72.6 million for the three months ended June 30, 2019. The decrease of $47.7 million was a result of a 1% increase in production volumes and a 66% decrease in the DD&A rate for the three months ended June 30, 2020 compared with the three months ended June 30, 2019. The increase in production accounted for a $0.8 million increase in DD&A expense, while the decrease in the DD&A rate accounted for a $48.5 million decrease in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended June 30, 2020, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $8.68 per Boe compared with $25.56 per Boe for the three months ended June 30, 2019. The decrease in the depletion rate of 66% was a result of recognizing a $1.2 billion impairment associated with our proved oil and gas properties during the three months ended March 31, 2020.

Unused Commitments. Unused commitments expense was $4.4 million for both the three months ended June 30, 2020 and June 30, 2019 related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense increased to $12.9 million for the three months ended June 30, 2020 from $12.4 million for the three months ended June 30, 2019. General and administrative expense on a

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Boe basis increased to $4.49 for the three months ended June 30, 2020 from $4.37 for the three months ended June 30, 2019. The increase in general and administrative expense for the three months ended June 30, 2020 was a result of severance and other employee-related non-recurring costs of which were associated with a reduction in force in May 2020 implemented in order to align our cost structure to the current operating environment.

Included in general and administrative expense is long-term cash and equity incentive compensation of $1.6 million and $2.3 million for the three months ended June 30, 2020 and 2019, respectively. The components of long-term cash and equity incentive compensation for the three months ended June 30, 2020 and 2019 are shown in the following table:

	Three Months Ended June 30,
	2020		2019
	(in thousands)
Nonvested common stock	$	1,150	$	1,533
Nonvested common stock units	202		318
Nonvested performance cash units (1)	198		445
Total	$	1,550	$	2,296

(1)The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Interest Expense. Interest expense increased to $15.4 million for the three months ended June 30, 2020 from $14.4 million for the three months ended June 30, 2019. The increase for the three months ended June 30, 2020 was due to increased borrowings under the Amended Credit Facility during the three months ended June 30, 2020. See Note 4 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative loss was $33.8 million for the three months ended June 30, 2020 compared with a gain of $19.5 million for the three months ended June 30, 2019. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of June 30, 2020 and 2019 or during the periods then ended.

The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility during the three months ended June 30, 2020 due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher wellhead revenues in the future.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:

	Three Months Ended June 30,
	2020		2019
	(in thousands)
Realized gain (loss) on derivatives (1)	$	40,611	$	(993)
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(225)		(20,933)
Unrealized gain (loss) on derivatives (1)	(74,179)		41,470
Total commodity derivative gain (loss)	$	(33,793)	$	19,544

(1)Realized and unrealized gains and losses on commodity derivatives are presented herein as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and

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unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more meaningful comparison to our peers.

During the three months ended June 30, 2020, approximately 78% of our oil volumes and 26% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $40.2 million and natural gas income of $0.4 million after settlements. During the three months ended June 30, 2019, approximately 90% of our oil volumes and 17% of our natural gas volumes were subject to financial hedges, which resulted in a decrease in oil income of $1.0 million and no change to natural gas income after settlements.

The COVID-19 pandemic caused a severe decline in current and estimated future oil and gas prices during the three months ended June 30, 2020. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

Income Tax (Expense) Benefit. For the three months ended June 30, 2020 and 2019, income tax expense of zero and $0.1 million was recognized, respectively. For the three months ended June 30, 2020, we determined that it was more likely than not that we would not be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax assets and liabilities, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of positive and negative evidence. As a result of the analysis conducted, we recorded a valuation allowance on the net deferred tax asset in excess of deferred tax liabilities. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets.

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Six Months Ended June 30, 2020 Compared with Six Months Ended June 30, 2019

	Six Months Ended June 30,				Increase (Decrease)
	2020		2019		Amount		Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	122,866	$	209,191	$	(86,325)	(41)	%
Other operating revenues	—		373		(373)		(100)	%
Total operating revenues	122,866		209,564		(86,698)		(41)	%
Operating Expenses
Lease operating expense	20,155		22,049		(1,894)		(9)	%
Gathering, transportation and processing expense	8,666		3,465		5,201		150	%
Production tax expense	(1,059)		12,798		(13,857)		*nm
Exploration expense	52		37		15		41	%
Impairment and abandonment expense	1,266,236		1,317		1,264,919		*nm
(Gain) loss on sale of properties	4,779		2,901		1,878		65	%
Depreciation, depletion and amortization	99,833		145,222		(45,389)		(31)	%
Unused commitment	8,836		8,821		15		—	%
General and administrative expense (1)	23,105		25,061		(1,956)		(8)	%
Merger transaction expense	—		2,414		(2,414)		(100)	%
Other operating expense, net	(502)		(20)		(482)		*nm
Total operating expenses	$	1,430,101	$	224,065	$	1,206,036	538	%
Production Data:
Oil (MBbls)	3,224		3,468		(244)		(7)	%
Natural gas (MMcf)	8,304		7,308		996		14	%
NGLs (MBbls)	1,170		953		217		23	%
Combined volumes (MBoe)	5,778		5,639		139		2	%
Daily combined volumes (Boe/d)	31,747		31,155		592		2	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	32.56	$	53.16	$	(20.60)	(39)	%
Natural gas (per Mcf)	1.06		1.90		(0.84)		(44)	%
NGLs (per Bbl)	7.74		11.47		(3.73)		(33)	%
Combined (per Boe)	21.26		37.10		(15.84)		(43)	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	53.99	$	54.45	$	(0.46)	(1)	%
Natural gas (per Mcf)	1.11		1.79		(0.68)		(38)	%
NGLs (per Bbl)	7.74		11.47		(3.73)		(33)	%
Combined (per Boe)	33.28		37.75		(4.47)		(12)	%
Average Costs (per Boe):
Lease operating expense	$	3.49	$	3.91	$	(0.42)	(11)	%
Gathering, transportation and processing expense	1.50		0.61		0.89		146	%
Production tax expense	(0.18)		2.27		(2.45)		*nm
Depreciation, depletion and amortization	17.28		25.75		(8.47)		(33)	%
General and administrative expense (1)	4.00		4.44		(0.44)		(10)	%

*Not meaningful.

(1)Included in general and administrative expense is long-term cash and equity incentive compensation of $2.0 million (or $0.35 per Boe) and $5.0 million (or $0.89 per Boe) for the six months ended June 30, 2020 and 2019, respectively.

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Production Revenues and Volumes. Production revenues decreased to $122.9 million for the six months ended June 30, 2020 from $209.2 million for the six months ended June 30, 2019. The decrease in production revenues was due to a 43% decrease in average realized prices before hedging, offset by a 2% increase in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $89.3 million, while the increase in production volumes increased production revenues by approximately $3.0 million.

Lease Operating Expense. LOE was $20.2 million for the six months ended June 30, 2020 and $22.0 million for the six months ended June 30, 2019. LOE decreased to $3.49 per Boe for the six months ended June 30, 2020 from $3.91 per Boe for the six months ended June 30, 2019. We started seeing a decrease in service industry costs during the six months ended June 30, 2020.

Gathering, Transportation and Processing Expense. GTP expense increased to $1.50 per Boe for the six months ended June 30, 2020 from $0.61 per Boe for the six months ended June 30, 2019.

Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred associated with gas and NGLs in the Hereford Field in the DJ Basin are included in GTP expense and costs incurred associated with gas and NGLs in the Northeast Wattenberg Field in the DJ Basin are included in production revenues. Costs incurred associated with oil are included in production revenues for both areas. See the “Revenue Recognition” section in Note 2 for additional information.

The increase in GTP per Boe for the six months ended June 30, 2020 compared to the six months ended June 30, 2019 was due to an increase in our production mix from the Hereford Field under the existing contractual arrangement, which has a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to negative $1.1 million for the six months ended June 30, 2020 from $12.8 million for the six months ended June 30, 2019. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for both periods included an annual true up of Colorado ad valorem tax based on actual assessments. Production taxes for the six months ended June 30, 2020 also included Colorado severance tax refunds of $1.8 million based on an audit of tax years 2015 to 2017. Excluding the ad valorem and severance tax adjustments and the severance tax refunds associated with tax years 2015 to 2017, production taxes as a percentage of oil, natural gas and NGL sales were 6.6% and 8.4% for the six months ended June 30, 2020 and 2019, respectively. The decrease in the rate for the six months ended June 30, 2020 was due to a decrease in our ad valorem effective tax rate.

Impairment and Abandonment Expense. We review our proved oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we estimate the expected undiscounted future net cash flows of our oil and gas properties using proved and risked probable and possible reserves based on our development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. We compare such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, we will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. We generally expect impairments of unproved properties to be more likely to occur in periods of low commodity prices because we will be less likely to devote capital to exploration activities.

Market conditions led to a decline in the recoverability of the carrying value of our oil and gas properties during the six months ended June 30, 2020. Since the carrying amount of our oil and gas properties was no longer recoverable, we impaired the carrying value to fair value. Therefore, we recognized non-cash impairment charges associated with our proved and

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unproved oil and gas properties during the six months ended June 30, 2020. Our impairment and abandonment expense for the six months ended June 30, 2020 and 2019 is summarized below:

	Six Months Ended June 30,
	2020		2019
Impairment of proved oil and gas properties	$	1,188,566	$	—
Impairment of unproved oil and gas properties	76,298		—
Abandonment expense	1,372		1,317
Total impairment and abandonment expense	$	1,266,236	$	1,317

Given the decline in current and estimated future commodity prices, we will continue to review our acreage position and future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.

Depreciation, Depletion and Amortization. DD&A decreased to $99.8 million for the six months ended June 30, 2020 compared with $145.2 million for the six months ended June 30, 2019. The decrease of $45.4 million was a result of a 2% increase in production and a 33% decrease in the DD&A rate for the six months ended June 30, 2020 compared with the six months ended June 30, 2019. The increase in production accounted for a $3.6 million increase in DD&A expense while the decrease in the DD&A rate accounted for a $49.0 million decrease in DD&A expense.

Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the six months ended June 30, 2020, the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $17.28 per Boe compared with $25.75 per Boe for the six months ended June 30, 2019. The decrease in the depletion rate of 33% was a result of recognizing a $1.2 billion impairment associated with our proved oil and gas properties during the six months ended June 30, 2020.

Unused Commitments. Unused commitments expense of $8.8 million for both the six months ended June 30, 2020 and 2019 related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense decreased to $23.1 million for the six months ended June 30, 2020 from $25.1 million for the six months ended June 30, 2019. General and administrative expense on a Boe basis decreased to $4.00 for the six months ended June 30, 2020 from $4.44 for the six months ended June 30, 2019.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.0 million and $5.0 million for the six months ended June 30, 2020 and 2019, respectively. The components of long-term cash and equity incentive compensation for the six months ended June 30, 2020 and 2019 are shown in the following table:

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Nonvested common stock	$	2,300	$	3,329
Nonvested common stock units	482		612
Nonvested performance cash units (1)	(776)		1,077
Total	$	2,006	$	5,018

(1)The nonvested performance cash units are accounted for as liability awards and will be settled in cash for the performance metrics that are met. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

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Merger Transaction Expense. Merger transaction expense of $2.4 million for the six months ended June 30, 2019 included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger.

Interest Expense. Interest expense increased to $29.8 million for the six months ended June 30, 2020 from $28.1 million for the six months ended June 30, 2019. The increase for the six months ended June 30, 2020 was due to increased borrowings under the Amended Credit Facility during the six months ended June 30, 2020. See Note 4 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative gain was $158.4 million for the six months ended June 30, 2020 compared with a loss of $85.6 million for the six months ended June 30, 2019. The gain for the six months ended June 30, 2020 compared to the loss for the six months ended June 30, 2019 was related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of June 30, 2020 and 2019 or during the periods then ended.

The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility during the six months ended June 30, 2020 due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher wellhead revenues in the future.

The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Realized gain (loss) on derivatives (1)	$	69,447	$	3,656
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	1,104		(57,073)
Unrealized gain (loss) on derivatives (1)	87,844		(32,230)
Total commodity derivative gain (loss)	$	158,395	$	(85,647)

(1)Realized and unrealized gains and losses on commodity derivatives are presented in the table as separate line items but are combined for a total commodity derivative gain (loss) in the Unaudited Consolidated Statements of Operations. This separate presentation is a non-GAAP measure. Management believes the separate presentation of the realized and unrealized commodity derivative gains and losses is useful because the realized cash settlement portion provides a better understanding of our hedge position. We also believe that this disclosure allows for a more meaningful comparison to our peers.

During the six months ended June 30, 2020, approximately 86% of our oil volumes and 12% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $60.7 million and natural gas income of $0.4 million. We also amended certain oil hedge contracts to terminate future hedged volumes, which resulted in additional oil income of $8.3 million during the six months ended June 30, 2020. During the six months ended June 30, 2019, approximately 90% of our oil volumes and 26% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $4.5 million and a decrease in natural gas income of $0.8 million after settlements.

The COVID-19 pandemic caused a severe decline in current and estimated future oil and gas prices during the six months ended June 30, 2020. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

Income Tax (Expense) Benefit. For the six months ended June 30, 2020 and 2019, income tax benefits of $95.3 million and $29.6 million were recognized, respectively. For the six months ended June 30, 2020, we determined that it was more likely than not that we would not be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of

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deferred tax assets and liabilities, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of positive and negative evidence. As a result of the analysis conducted, we recorded a valuation allowance on the net deferred tax asset in excess of deferred tax liabilities. For the six months ended June 30, 2020, we have recorded a deferred tax liability of $2.1 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation have been net cash provided by operating activities, including commodity hedges, sales and other issuances of equity and debt securities, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity.

We may from time to time seek to retire, purchase or otherwise refinance our outstanding debt securities through cash purchases and/or exchanges, in open market purchases, privately negotiated transactions, exchange offers or otherwise. Any such transactions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. The amounts involved may be material.

Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. Given the levels of market volatility and disruption due to the COVID-19 pandemic, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to provide funding to borrowers.

At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under the Amended Credit Facility. At June 30, 2020, we had cash and cash equivalents of $2.7 million and $175.0 million outstanding under the Amended Credit Facility. On May 21, 2020, the Amended Credit Facility borrowing base was reduced from $500.0 million to $300.0 million and the applicable margins for interest and commitment fee rates were increased. In addition, provisions were added requiring the availability under the Amended Credit Facility to be at least $50.0 million and our weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. Our available borrowing capacity under the Amended Credit Facility as of June 30, 2020 was $53.3 million, after taking into account the $50.0 million minimum availability requirement and outstanding irrevocable letter of credit of $21.7 million related to a firm transportation agreement.

As of the date of this filing, August 3, 2020, we believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility to meet our obligations and commitments for the next twelve months. We deferred drilling and completion activity starting in May 2020 and will continue to defer until oil prices improve to a level that allows us to meet our target return threshold. In addition, we are currently in compliance with all financial covenants under our Amended Credit Facility and have $71.2 million available for future borrowing, after taking into consideration payments on the Amended Credit Facility of $20 million made in July 2020 and letter of credit balances of $23.8 million.

Cash Flow from Operating Activities

Net cash provided by operating activities for the six months ended June 30, 2020 and 2019 was $60.3 million and $98.5 million, respectively. The decrease in net cash provided by operating activities was due to a decrease in production revenues and a decrease in working capital changes due to the timing of cash receipts and disbursements. These were partially offset by an increase in cash settlements of derivatives.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict.

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To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap and swaption contracts to receive fixed prices for a portion of our production. At June 30, 2020, we had in place crude oil and natural gas swaps covering portions of our 2020 and 2021 production and crude oil swaptions covering portions of our 2022 production. In addition, we had oil roll swaps covering portions of our 2020 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The following table includes all hedges entered into through July 20, 2020.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price (1)
Swaps
2020
Oil	2,760,000	Bbls	$	56.59	WTI
Natural gas	3,680,000	MMBtu	$	1.83	NWPL
2021
Oil	3,098,000	Bbls	$	54.30	WTI
Natural gas	5,790,000	MMBtu	$	2.13	NWPL
Oil Roll Swaps (2)
2020
Oil	276,500	Bbls	$	(1.47)	WTI
Swaptions
2022
Oil	1,092,000	Bbls	$	55.08	WTI

(1)WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month.

(2)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

By removing the price volatility from a portion of our oil and natural gas revenue, we have mitigated, but not eliminated, the potential effects of changing prices on our operating cash flow for the relevant period. While mitigating negative effects of falling commodity prices, these derivative contracts also limit the benefits we would receive from increases in commodity prices.

It is our policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. Our derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. We are not required to provide any credit support to our counterparties other than cross collateralization with the properties securing the Amended Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Amended Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Amended Credit Facility, we may not be able to set-off amounts owed by us under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility.

Capital Expenditures

Our capital expenditures are summarized in the following tables for the periods indicated:

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	Six Months Ended June 30,
Basin/Area	2020		2019
	(in millions)
DJ Basin	$	93.4	$	246.9
Other	1.8		3.6
Total	$	95.2	$	250.5

	Six Months Ended June 30,
	2020		2019
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	—	$	0.7
Drilling, development, exploration and exploitation of oil and natural gas properties	92.4		230.1
Gathering and compression facilities	2.1		9.3
Geologic and geophysical costs	0.4		6.8
Furniture, fixtures and equipment	0.3		3.6
Total	$	95.2	$	250.5

For the three months ending September 30, 2020, capital expenditures are anticipated to be approximately $10.0 million. As oil prices declined significantly due to the COVID-19 pandemic, we deferred drilling and completion activity starting in May 2020 and will continue deferring until oil prices improve to a level that allows us to meet our target return threshold. We may continue to adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control.

Financing Activities

Amended Credit Facility. On May 21, 2020, the Amended Credit Facility aggregate elected commitment amount and borrowing base were reduced from $500.0 million to $300.0 million and the applicable margins for interest and commitment fee rates were increased. In addition, provisions were added requiring the availability under the Amended Credit Facility to be at least $50.0 million and our weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. We had $175.0 million and $140.0 million outstanding under the Amended Credit Facility as of June 30, 2020 and December 31, 2019, respectively. Our available borrowing capacity was $53.3 million as of June 30, 2020 after taking into account the $50.0 million minimum availability requirement as well as a $21.7 million letter of credit, which was issued as credit support for future payments under a contractual obligation. As of the date of this filing, August 3, 2020, our available borrowing capacity is at $71.2 million after taking into consideration payments on the Amended Credit Facility of $20 million made in July 2020 and letter of credit balances of $23.8 million.

The current maturity date of the Amended Credit Facility is July 16, 2022. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

The borrowing base is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. If the borrowing base is reduced below the then-outstanding amount under the amended Credit Facility, we will be required to repay the excess of the outstanding amount over the borrowing base over a period of four months. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt.

We have financial covenants associated with our Amended Credit Facility that are measured each fiscal quarter. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. However, if current market conditions continue, we may not be able to maintain compliance with these financial covenants. In particular, we may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of

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2021. Further, if our independent auditor were to include an explanatory paragraph regarding our ability to continue as a “going concern” in the auditors’ report on our financial statements for the year ending December 31, 2020, this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, we may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under our senior notes and we may not have other sources of capital to repay the amounts due.

Our outstanding debt is summarized below:

		As of June 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	175,000	$	—	$	175,000	$	140,000	$	—	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,954)		348,046		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,373)		271,627		275,000		(3,717)		271,283
Total Long-Term Debt (1)		$	800,000	$	(5,327)	$	794,673	$	765,000	$	(6,089)	$	758,911

(1)See Note 4 for additional information.

Guarantor Structure. The issuer of our 7.0% Senior Notes and 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett), or Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the Merger, HighPoint Resources Corporation, or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. In addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of Subsidiary Issuer on August 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. We have no other subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor.

In March 2020, the Securities and Exchange Commission (“SEC”) issued a final rule, Financial Disclosures About Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities, which amends the disclosure requirements related to certain registered securities which currently require separate financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. Alternative disclosures are available for each subsidiary issuer/guarantor when they are consolidated and the parent company either issues or guarantees, on a full and unconditional basis, the guaranteed securities. If a registrant qualifies for alternative disclosure, the registrant may omit summarized financial information when not material and instead provide narrative disclosure of the guarantor structure, including terms and conditions of the guarantees.

We qualify for alternative disclosure, therefore, as of March 2020, we are no longer presenting condensed consolidating financial information for our parent guarantor, subsidiary issuer, or subsidiary guarantor of our debt securities. The assets, liabilities and results of operations of the issuer and guarantors of the guaranteed securities on a combined basis are not materially different than corresponding amounts presented in the consolidated financial statements of the parent company as all of the material operating assets and liabilities, and all of our material operations reside within the subsidiary issuer.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, 7.0% Senior Notes or 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities could be affected by our credit rating at the time any such financing activities are conducted.

Contractual Obligations. A summary of our contractual obligations as of June 30, 2020 is provided in the following table:

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	Payments Due by Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	Twelve Months Ended June 30, 2021		Twelve Months Ended June 30, 2022		Twelve Months Ended June 30, 2023		Twelve Months Ended June 30, 2024		Twelve Months Ended June 30, 2025		After June 30, 2025
	(in thousands)
Notes payable (1)	$	390	$	12	$	—	$	175,000	$	—	$	—	$	175,402
7.0% Senior Notes (2)	24,500		24,500		362,250		—		—		—		411,250
8.75% Senior Notes (3)	24,063		24,063		24,063		24,063		299,061		—		395,313
Firm transportation agreements (4)	25,973		12,240		14,600		14,640		12,160		—		79,613
Gas gathering and processing agreements (5)	2,092		4,265		—		—		—		—		6,357
Asset retirement obligations (6)	2,619		2,004		2,006		2,150		2,127		15,663		26,569
Operating leases (7)	2,708		2,490		2,219		2,051		2,137		6,486		18,091
Other (8)	1,471		1,285		11,485		15,912		—		—		30,153
Total	$	83,816	$	70,859	$	416,623	$	233,816	$	315,485	$	22,149	$	1,142,748

(1)Included in notes payable is the outstanding principal amount under our Amended Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. The current maturity date of the Amended Credit Facility is July 16, 2022. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022. Also included in notes payable is interest on a $21.7 million letter of credit, which will continue to decrease ratably per month until it expires on August 31, 2021. Interest accrues at 3.0% and 0.125% per annum for participation fees and fronting fees, respectively.

(2)On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $12.3 million.

(3)On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million.

(4)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the processing facility or pipeline.

(5)Includes a gas gathering and processing contract which requires us to deliver a minimum volume of natural gas to a midstream entity for gathering and processing on a monthly basis. The contract requires us to pay a fee associated with the contracted volumes regardless of the amount delivered.

(6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(7)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property.

(8)Includes $10.2 million for the twelve months ended June 30, 2023 and $15.3 million for the twelve months ended June 30, 2024 related to a drilling commitment with a joint interest partner which requires us to drill and complete two wells by July 2022 and three wells by 2023. If the drilling commitment is not met, the Company must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. Also includes fresh water commitment contracts which require us to purchase a minimum volume of fresh water from a supplier. The contracts require us to pay a fee associated with the contracted volumes regardless of the amount delivered.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of June 30, 2020.

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Trends and Uncertainties

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see “Risk Factors” in Part II of this report. The following trends and uncertainties are related to the COVID-19 pandemic.

Declining Commodity Prices. The severe decline in oil prices that occurred in the first quarter of 2020 due to the COVID-19 pandemic has adversely affected the economics of our existing wells and planned future wells, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020. In addition, we deferred drilling and completion activity starting in May 2020 for the foreseeable future. Our results of operations for the three and six months ended June 30, 2020 were mitigated from price declines by hedges in place on 78% and 86%, respectively, of our oil production. We currently have hedged approximately 92% and 56% of our expected remaining 2020 oil and natural gas production, respectively, at price levels that provide some economic certainty to our capital investments. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.

Employee Health and Safety. The health and safety of our employees and the community is our highest priority. We are also cognizant that supplying reliable energy to our communities and the nation is an essential function. The federal government, through the Cybersecurity and Infrastructure Security Administration, as well as Colorado state and local “stay-at-home” orders, have provided exemptions for oil and gas workers.

Under our business continuity plan, we were rapidly able to switch to remote operations in response to the COVID-19 pandemic in early March. Beginning March 16th, we successfully transitioned to full remote access and operations, in both the Denver headquarters office and at the field level. The successful transition to remote operations was virtually seamless. In late May, we began to transition back to increased office presence on a staggered schedule so that approximately 50% of the work force is in the office on a daily basis.

Supply Chain Issues. We have not experienced any recent challenges with respect to obtaining oil field goods and services. However, as oil service and supply companies cut work force and stack rigs and frac fleets, there is the potential for challenges on this front when activity begins to ramp up, although the related timing is highly uncertain.

Access to Downstream Markets. We are not currently experiencing constraints associated with midstream gas processing or crude oil transportation. However, crude storage facilities are operating close to maximum capacity, which could result in the need for us to shut-in production. Accordingly, we have engaged in contingency planning for that possibility.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

The primary objective of the following information is to provide forward-looking quantitative and qualitative information about our potential exposure to market risks. The term “market risk” refers to the risk of loss arising from adverse changes in oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

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Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. oil and natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and was especially volatile during the six months ended June 30, 2020, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the six months ended June 30, 2020, our income before income taxes would have decreased by approximately $1.0 million for each $5.00 per barrel decrease in crude oil prices, approximately $0.7 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $1.1 million for each $1.00 per barrel decrease in NGL prices.

We routinely enter into commodity hedges relating to a portion of our projected production revenue through various financial transactions that hedge future prices received. These transactions may include financial price swaps whereby we will receive a fixed price and pay a variable market price to the contract counterparty or swaptions whereby the counterparty, on a specific date, may extend an existing fixed-price swap for a certain period of time or increase the notional volumes of an existing fixed-price swap. We may also enter into oil roll swaps, which fix the differential in pricing between the NYMEX WTI calendar month average and the physical crude delivery month (“oil roll swaps”). These commodity hedging activities are intended to support oil, natural gas and NGL prices at targeted levels that provide an acceptable rate of return and to manage our exposure to oil, natural gas and NGL price fluctuations. We do not enter into any market risk sensitive instruments for trading purposes.

Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. As of July 20, 2020, we have swap and swaption contracts related to oil and natural gas volumes in place for the following periods indicated:

	July – December 2020			For the year 2021			For the year 2022
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps
Oil (Bbls)	2,760,000	$	56.59	3,098,000	$	54.30	—	$	—
Natural Gas (MMbtu)	3,680,000	$	1.83	5,790,000	$	2.13	—	$	—
Oil Roll Swaps (1)
Oil (Bbls)	276,500	$	(1.47)	—	$	—	—	$	—
Swaptions
Oil (Bbls)	—	$	—	—	$	—	1,092,000	$	55.08

(1)These contracts establish a fixed amount for the differential between the oil roll and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

Further detail of these hedges is summarized in the table presented under “Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities.”

Interest Rate Risk

At June 30, 2020, we had $175.0 million outstanding under our Amended Credit Facility, which bears interest at floating rates. The weighted average annual interest rate incurred on this debt for the six months ended June 30, 2020 was 3.0%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the six months ended June 30, 2020 would have resulted in an estimated $0.8 million increase in interest expense assuming a similar average debt level to the six months ended June 30, 2020. We also had $350.0 million principal amount of 7.0% Senior Notes and $275.0 million principal amount of 8.75% Senior Notes outstanding at June 30, 2020.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of June 30, 2020, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the

41

effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of June 30, 2020.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the second quarter of 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are involved in various legal or governmental proceedings in the ordinary course of business. These proceeding are subject to the uncertainties inherent in any litigation. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management does not believe that the resolution of any currently pending proceeding will have a material adverse effect on our financial condition or results of operations, other than the following.

Sterling Energy Investments LLC v. HighPoint Operating Corporation, 2020CV32034, District Court in Denver, Colorado. On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint Operating Corporation, a subsidiary of ours, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017, by and between HighPoint Operating Corporation and Sterling. Sterling alleges that HighPoint Operating Corporation breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. We vigorously deny Sterling’s claims. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, we filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Gathering Agreement. We are seeking monetary damages in an amount not yet specified.

Disclosure of certain environmental matters are required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we reasonably believe could exceed $100,000. We have received some Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”) alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. We are engaged in discussions regarding resolution of the alleged violations. We have recognized a liability of $1.0 million associated with the NOAVs, as they are probable and reasonably estimable.

Item 1A. Risk Factors.

Please refer to the “Risk Factors” section of our Annual Report on Form 10-K for the year ended December 31, 2019. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2019 and subsequent reports filed with the SEC. These risks and uncertainties are not the only ones facing us, and there may be additional matters that we are unaware of or that we currently consider immaterial. All of these could adversely affect our business, financial condition, results of operations and cash flows and, thus, the value of an investment in our Company. There have been no material changes to the risk factors previously disclosed in our Annual Report on Form 10-K for the year ended December 31, 2019 other than as detailed below.

The COVID-19 pandemic and recent developments in the oil and gas industry have and could continue to materially adversely affect our operations during 2020 and possibly beyond.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil and gas demand. In response, the Organization of Petroleum Exporting Countries (“OPEC”), along with non-OPEC oil-producing countries (collectively known as “OPEC+”), initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of $30.45 per barrel for the month of March 2020 and $16.70 per barrel for the month of April 2020 before increasing to an average of $38.31 per barrel for the month of June 2020, compared to $59.80 for the month of December 2019. These declines in prices have adversely affected the economics of our existing wells and planned future development, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020. Additional impacts to our results of operations for the three and six months ended June 30, 2020 were mitigated by hedges in place on 78% and 86%, respectively, of our oil production, however, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The substantial decline in oil price has increased the volatility and amplitude of risks we face as described in this report and in our Annual Report on Form 10-K for the year ended December 31, 2019. If oil prices do not improve, capital availability, our

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liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. There is uncertainty around the timing and recovery of the global economy from COVID-19 and its effects on the supply and demand for crude oil. Therefore, we expect continued volatility and uncertainty in the outlook for near to medium term oil prices.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time or cause us to change drilling plans and/or forego lease renewals or cause significant decreases in property market values, we may be required to take an impairment against the carrying values of our proved and/or unproved properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to take an impairment against the carrying value of our properties. An impairment constitutes a non-cash charge to earnings. For the three months ended March 31, 2020, we recorded non-cash impairment charges of approximately $1.3 billion on proved and unproved oil and gas properties, and if market or other economic conditions deteriorate further or if oil and gas prices continue to decline, we may incur additional impairment charges, which may have a material adverse effect on our results of operations.

Any inability to comply with the covenants under our Amended Credit Facility may raise substantial doubt about our ability to continue as a going concern.

If we fail to comply with any covenants under our Amended Credit Facility, an event of default could result, in which event we will discuss available options with the lenders, which may include covenant relief or other amendments to the Amended Credit Facility. If such discussions were ultimately unsuccessful and an Event of Default exists, all outstanding amounts under the Amended Credit Facility may become due and payable and we may not have other sources of capital to repay such amounts. Such an occurrence could also lead to an event of default and an acceleration of amounts due under the indentures governing our senior notes. Any such occurrence could raise substantial doubt about our ability to continue as a going concern. There is no assurance that any particular actions with respect to refinancing or restructuring our debt or curing potential defaults under our debt instruments could be completed or would be sufficient. Any such actions may have a material adverse effect on the value of our common stock. If current market conditions continue, we may not be able to maintain compliance with our financial covenants. In particular, we may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 2021. Further, if our independent auditor were to include an explanatory paragraph regarding our ability to continue as a “going concern” in the auditors’ report on our financial statements for the year ending December 31, 2020, this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, we may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under our senior notes and we may not have other sources of capital to repay the amounts due.

If we cannot meet the financial compliance standards for continued listing on the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which could have an adverse impact on the trading volume, liquidity and market price of our common stock.

The NYSE Listed Company Manual has a set of financial compliance standards we must meet to avoid being delisted from the NYSE. The financial compliance standards are defined below:

•average market capitalization of not less than $50 million over a 30 trading day period and stockholders’ equity of not less than $50 million;

•average closing share price of $1.00 over a 30 trading day period; and

•average market capitalization of not less than $15 million over a 30 day trading period, which is a minimum threshold for continued listing with no cure period.

On March 10, 2020, we were notified by the NYSE that the average closing price of our common stock over the prior 30- consecutive trading day period was below that level. The NYSE Listed Company Manual sets out rules and processes to cure non-compliance with this standard. For instance, an issuer generally has six months to cure the listing standard related to stock price (including through a reverse-stock split, which was approved at the annual stockholders meeting on April 28, 2020), during which time the issuer’s common stock would continue to be traded on the NYSE, subject to compliance with the other continued listing standards. However, an immediate delisting could occur if the trading price of the stock falls below a level

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determined by the NYSE. A delisting of our common stock from the NYSE could negatively impact us because it could reduce the liquidity and market price of our common stock and reduce the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing, and/or diminish the value of equity incentives available to provide to our employees.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

Unregistered Sales of Securities

There were no sales of unregistered equity securities during the period covered by this report.

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended June 30, 2020:

Period	Total Number of Shares (1)	Weighted Average Price Paid Per Share		Total Number of  Shares (or Units) Purchased as Part of Publicly Announced Plans or Programs	Maximum Number (or Approximate  Dollar Value) of Shares (or Units) that May Yet Be Purchased Under the Plans or Programs
April 1 – 30, 2020	—	$	—	—	—
May 1 – 31, 2020	7,735	0.28		—	—
June 1 – 30, 2020	34,301	0.43		—	—
Total	42,036	0.41		—	—

(1)Represents shares delivered by employees to satisfy tax withholding obligations resulting from the vesting of restricted shares of common stock issued pursuant to our employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit Number	Description of Exhibits
10	First Amendment to the Fourth Amended and Restated Credit Agreement, dated as of May 21, 2020, among HighPoint Resources Corporation, as guarantor, HighPoint Operating Corporation, as borrower, borrower’s subsidiary, and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on May 26, 2020.]
22	Subsidiary Guarantors and Issuers of Guaranteed Securities.
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.

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Exhibit Number	Description of Exhibits
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.
101.INS	Instance Document (The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.)
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

46

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		HIGHPOINT RESOURCES CORPORATION
Date:	August 3, 2020	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	August 3, 2020	By:	/s/ William M. Crawford
			William M. Crawford
			Chief Financial Officer
			(Principal Accounting Officer)

47

EX-22

Exhibit 22

SUBSIDIARY GUARANTORS AND ISSUERS OF GUARANTEED SECURITIES

7.0% Senior Notes Due 2022

8.75% Senior Notes Due 2025

Entity	Subsidiary Issuer or Guarantor	Relationship to Registrant
HighPoint Operating Corporation	Subsidiary Issuer	Wholly-owned subsidiary of Registrant
Fifth Pocket Production, LLC	Subsidiary Guarantor	Wholly-owned subsidiary of HighPoint Operating Corporation

EX-31.1

Exhibit 31.1

CERTIFICATION

I, R. Scot Woodall, certify that:

1.I have reviewed this quarterly report on Form 10-Q of HighPoint Resources Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 3, 2020

/s/ R. Scot Woodall

R. Scot Woodall

Chief Executive Officer, President and Director
(Principal Executive Officer)

EX-31.2

Exhibit 31.2

CERTIFICATION

I, William M. Crawford, certify that:

1.I have reviewed this quarterly report on Form 10-Q of HighPoint Resources Corporation;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a.Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b.Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c.Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d.Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5.The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a.All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b.Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: August 3, 2020

/s/ William M. Crawford

William M. Crawford

Chief Financial Officer
(Principal Financial Officer)

EX-32.1

Exhibit 32.1

HIGHPOINT RESOURCES CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this quarterly report on Form 10-Q of HighPoint Resources Corporation for the fiscal quarter ended June 30, 2020, I, R. Scot Woodall, Chief Executive Officer and President of HighPoint Resources Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Form 10-Q for the fiscal quarter ended June 30, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Form 10-Q for the fiscal quarter ended June 30, 2020 fairly presents, in all material respects, the financial condition and results of operations of HighPoint Resources Corporation for the periods presented therein.

Date: August 3, 2020

/s/ R. Scot Woodall

R. Scot Woodall

Chief Executive Officer and President

(Principal Executive Officer)

EX-32.2

Exhibit 32.2

HIGHPOINT RESOURCES CORPORATION

SARBANES-OXLEY ACT SECTION 906 CERTIFICATION

In connection with this quarterly report on Form 10-Q of HighPoint Resources Corporation for the fiscal quarter ended June 30, 2020, I, William M. Crawford, Chief Financial Officer of HighPoint Resources Corporation, hereby certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that:

1.This Form 10-Q for the fiscal quarter ended June 30, 2020 fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and

2.The information contained in this Form 10-Q for the fiscal quarter ended June 30, 2020 fairly presents, in all material respects, the financial condition and results of operations of HighPoint Resources Corporation for the periods presented therein.

Date: August 3, 2020

/s/ William M. Crawford

William M. Crawford

Chief Financial Officer

(Principal Financial Officer)

XML

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2020	Jul. 20, 2020
Document Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Quarterly Report	true
Document Period End Date	Jun. 30, 2020
Document Transition Report	false
Entity File Number	001-38435
Entity Registrant Name	HighPoint Resources Corp
Entity Central Index Key	0001725526
Current Fiscal Year End Date	--12-31
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q2
Entity Incorporation, State or Country Code	DE
Entity Tax Identification Number	82-3620361
Entity Address, Address Line One	555 17th Street, Suite 3700
Entity Address, City or Town	Denver
Entity Address, State or Province	CO
Entity Address, Postal Zip Code	80202
City Area Code	303
Local Phone Number	293-9100
Title of 12(b) Security	Common stock, $0.001 par value
Trading Symbol	HPR
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		215,264,180

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Current Assets:
Cash and cash equivalents	$ 2,736	$ 16,449
Accounts receivable, net of allowance	59,277	62,120
Derivative assets	72,236	3,916
Prepayments and other current assets	5,962	3,952
Total current assets	140,211	86,437
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,749,042	2,644,129
Unproved oil and gas properties, excluded from amortization	243,309	357,793
Furniture, equipment and other	30,739	29,804
Property, plant and equipment, gross	3,023,090	3,031,726
Accumulated depreciation, depletion, amortization and impairment	(2,235,234)	(967,552)
Total property and equipment, net	787,856	2,064,174
Derivative assets	15,546	0
Other noncurrent assets	8,375	5,441
Total	951,988	2,156,052
Current Liabilities:
Accounts payable and accrued liabilities	42,077	71,638
Amounts payable to oil and gas property owners	25,226	37,922
Production taxes payable	46,985	61,507
Derivative liabilities	0	4,411
Total current liabilities	114,288	175,478
Long-term debt, net of debt issuance costs	794,673	758,911
Asset retirement obligations	23,950	23,491
Deferred income taxes	2,137	97,418
Other noncurrent liabilities	14,761	17,436
Commitments and contingencies (Note 11)
Stockholders’ Equity:
Common stock, $0.001 par value; authorized 400,000,000 shares; 215,409,996 and 213,669,597 shares issued and outstanding at June 30, 2020 and December 31, 2019, respectively, with 3,168,704 and 2,968,497 shares subject to restrictions, respectively	212	211
Additional paid-in capital	1,779,906	1,777,779
Retained earnings (accumulated deficit)	(1,777,939)	(694,672)
Treasury stock, at cost: zero shares at June 30, 2020 and December 31, 2019	0	0
Total stockholders’ equity	2,179	1,083,318
Total	$ 951,988	$ 2,156,052

XML

CONSOLIDATED BALANCE SHEETS (UNAUDITED) (Parenthetical) - $ / shares	Jun. 30, 2020	Dec. 31, 2019
Statement of Financial Position [Abstract]
Common stock, par value (in dollars per share)	$ 0.001	$ 0.001
Common stock, shares authorized (in shares)	400,000,000	400,000,000
Common stock, shares issued (in shares)	215,409,996	213,669,597
Common stock, shares outstanding (in shares)	215,409,996	213,669,597
Common stock, shares subject to restrictions (in shares)	3,168,704	2,968,497
Treasury stock, shares (in shares)	0	0

XML

CONSOLIDATED STATEMENTS OF OPERATIONS (UNAUDITED) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Operating Revenues:
Total operating revenues	$ 43,300	$ 107,584	$ 122,866	$ 209,564
Operating Expenses:
Production tax expense	1,449	8,905	(1,059)	12,798
Exploration expense	21	12	52	37
Impairment and abandonment expense	810	995	1,266,236	1,317
(Gain) loss on sale of properties	4,779	2,906	4,779	2,901
Depreciation, depletion and amortization	24,908	72,612	99,833	145,222
Unused commitments	4,378	4,352	8,836	8,821
General and administrative expense	12,890	12,401	23,105	25,061
Merger transaction expense	0	0	0	2,414
Other operating expenses, net	(557)	4	(502)	(20)
Total operating expenses	62,006	114,701	1,430,101	224,065
Operating Income (Loss)	(18,706)	(7,117)	(1,307,235)	(14,501)
Other Income and Expense:
Interest and other income (expense)	259	154	64	468
Interest expense	(15,388)	(14,381)	(29,771)	(28,060)
Commodity derivative gain (loss)	(33,793)	19,544	158,395	(85,647)
Total other income and expense	(48,922)	5,317	128,688	(113,239)
Income (Loss) before Income Taxes	(67,628)	(1,800)	(1,178,547)	(127,740)
(Provision for) Benefit from Income Taxes	0	(110)	95,280	29,601
Net Income (Loss)	$ (67,628)	$ (1,910)	$ (1,083,267)	$ (98,139)
Net Income (Loss) Per Common Share, Basic (in dollars per share)	$ (0.32)	$ (0.01)	$ (5.12)	$ (0.47)
Net Income (Loss) Per Common Share, Diluted (in dollars per share)	$ (0.32)	$ (0.01)	$ (5.12)	$ (0.47)
Weighted Average Common Shares Outstanding, Basic (in shares)	211,894,790	210,377,152	211,503,310	210,155,678
Weighted Average Common Shares Outstanding, Diluted (in shares)	211,894,790	210,377,152	211,503,310	210,155,678
Oil, gas and NGL production
Operating Revenues:
Production and other revenues	$ 43,300	$ 107,486	$ 122,866	$ 209,191
Other operating revenues, net
Operating Revenues:
Production and other revenues	0	98	0	373
Lease operating expense
Operating Expenses:
Cost of goods and services	9,074	10,772	20,155	22,049
Gathering, transportation and processing expense
Operating Expenses:
Cost of goods and services	$ 4,254	$ 1,742	$ 8,666	$ 3,465

XML

CONSOLIDATED STATEMENTS OF CASH FLOWS (UNAUDITED) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Operating Activities:
Net Income (Loss)	$ (1,083,267)	$ (98,139)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	99,833	145,222
Deferred income taxes	(95,280)	(29,601)
Impairment and abandonment expense	1,266,236	1,317
Commodity derivative (gain) loss	(158,395)	85,647
Settlements of commodity derivatives	69,447	3,656
Stock compensation and other non-cash charges	2,645	6,980
Amortization of deferred financing costs	2,287	1,275
(Gain) loss on sale of properties	4,779	2,901
Change in operating assets and liabilities:
Accounts receivable	(2,413)	18,475
Prepayments and other assets	(1,905)	(1,463)
Accounts payable, accrued and other liabilities	(16,441)	(6,733)
Amounts payable to oil and gas property owners	(12,696)	(22,923)
Production taxes payable	(14,522)	(8,069)
Net cash provided by (used in) operating activities	60,308	98,545
Investing Activities:
Additions to oil and gas properties, including acquisitions	(110,841)	(258,153)
Additions of furniture, equipment and other	(653)	(3,574)
Other investing activities	3,189	(98)
Net cash provided by (used in) investing activities	(108,305)	(261,825)
Financing Activities:
Proceeds from debt	120,000	150,000
Principal payments on debt	(85,000)	(1,859)
Other financing activities	(716)	(1,523)
Net cash provided by (used in) financing activities	34,284	146,618
Increase (Decrease) in Cash and Cash Equivalents	(13,713)	(16,662)
Beginning Cash and Cash Equivalents	16,449	32,774
Ending Cash and Cash Equivalents	$ 2,736	$ 16,112

XML

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY (UNAUDITED) - USD ($) $ in Thousands	Total	Common Stock	Additional Paid-In Capital	Retained Earnings (Accumulated Deficit)	Treasury Stock
Balance at Dec. 31, 2018	$ 1,212,098	$ 210	$ 1,771,730	$ (559,842)	$ 0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock activity and shares exchanged for tax withholding	(1,506)				(1,506)
Stock-based compensation	3,940		3,940
Retirement of treasury stock	0		(1,506)		1,506
Net income (loss)	(98,139)			(98,139)
Balance at Jun. 30, 2019	1,116,393	210	1,774,164	(657,981)	0
Balance at Mar. 31, 2019	1,116,475	210	1,772,336	(656,071)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock activity and shares exchanged for tax withholding	(22)				(22)
Stock-based compensation	1,850		1,850
Retirement of treasury stock	0		(22)		22
Net income (loss)	(1,910)			(1,910)
Balance at Jun. 30, 2019	1,116,393	210	1,774,164	(657,981)	0
Balance at Dec. 31, 2019	1,083,318	211	1,777,779	(694,672)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock activity and shares exchanged for tax withholding	(653)	1			(654)
Stock-based compensation	2,781		2,781
Retirement of treasury stock	0		(654)		654
Net income (loss)	(1,083,267)			(1,083,267)
Balance at Jun. 30, 2020	2,179	212	1,779,906	(1,777,939)	0
Balance at Mar. 31, 2020	68,472	212	1,778,571	(1,710,311)	0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Restricted stock activity and shares exchanged for tax withholding	(18)				(18)
Stock-based compensation	1,353		1,353
Retirement of treasury stock	0		(18)		18
Net income (loss)	(67,628)			(67,628)
Balance at Jun. 30, 2020	$ 2,179	$ 212	$ 1,779,906	$ (1,777,939)	$ 0

XML

Organization	6 Months Ended
	Jun. 30, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Organization	OrganizationHighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”), is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”). The Company became the successor to Bill Barrett Corporation (“Bill Barrett”), on March 19, 2018, upon closing of the transactions contemplated by the Agreement and Plan of Merger, dated December 4, 2017 (the “Merger Agreement”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC (“Fifth Creek”) (the “Merger”). As a result of the Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. The Company currently conducts its activities principally in the Denver Julesburg Basin (“DJ Basin”) in Colorado. Except where the context indicates otherwise, references herein to the “Company” with respect to periods prior to the completion of the Merger refer to Bill Barrett and its subsidiaries.

XML

Summary of Significant Accounting Policies

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company’s Annual Report on Form 10-K for the year ended December 31, 2019 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. 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 Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure 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 initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, right-of-use assets and lease liabilities, deferred income taxes, the timing of dry hole costs, impairments of proved and unproved oil and gas properties and fair values of derivative instruments and stock-based payment awards. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Oil, gas and NGL sales	$	32,383	$	50,171
Due from joint interest owners (1)	23,796		9,551
Other	3,129		2,419
Allowance for doubtful accounts	(31)		(21)
Total accounts receivable	$	59,277	$	62,120

(1)Includes $12.9 million associated with one joint interest partner. In the event of nonpayment, the Company expects to net the outstanding amount against certain revenues payable to this joint interest partner.

Oil and Gas Properties. The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Proved properties	$	721,174	$	725,964
Wells and related equipment and facilities	1,910,527		1,805,136
Support equipment and facilities	105,397		99,540
Materials and supplies	11,944		13,489
Total proved oil and gas properties	$	2,749,042	$	2,644,129
Unproved properties	182,605		265,387
Wells and facilities in progress	60,704		92,406
Total unproved oil and gas properties, excluded from amortization	$	243,309	$	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,224,428)		(958,475)
Total oil and gas properties, net	$	767,923	$	2,043,447

The Company reviews proved oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on an analysis of quantitative and qualitative factors existing as of the balance sheet date including the Company’s development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, income taxes and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, the Organization of Petroleum Exporting Countries (“OPEC”), along with non-OPEC oil-producing countries (collectively known as “OPEC+”), initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of $30.45 per barrel for the month of March 2020, compared to an average of $59.80 per barrel for the month of December 2019. These events led to a decline in the recoverability of the carrying value of the Company’s oil and gas properties during the three months ended March 31, 2020. Since the carrying amount of the oil and gas properties was no longer recoverable, the Company impaired the carrying value to fair value. Therefore, the Company recognized non-cash impairment

charges during the three months ended March 31, 2020, which were included within impairment and abandonment expense in the Unaudited Consolidated Statements of Operations.

For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company’s determination of fair value associated with the Company’s proved and unproved oil and gas properties. Through the use of the Company’s production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the proved developed producing (“PDP”) and proved developed non-producing (“PDN”) reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the proved undeveloped (“PUD”), probable (“PROB”) and possible (“POSS”) reserves. The Company’s impairment and abandonment expense for the three and six months ended June 30, 2020 and 2019 is summarized below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Impairment of proved oil and gas properties	$	—	$	—	$	1,188,566	$	—
Impairment of unproved oil and gas properties	—		—		76,298		—
Abandonment expense	810		995		1,372		1,317
Total impairment and abandonment expense	$	810	$	995	$	1,266,236	$	1,317

Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Accrued drilling, completion and facility costs	$	12,957	$	25,667
Accrued lease operating, gathering, transportation and processing expenses	7,364		8,046
Accrued general and administrative expenses	6,910		6,612
Accrued interest payable	6,681		6,832
Trade payables	3,951		17,488
Operating lease liability	1,954		1,287
Other	2,260		5,706
Total accounts payable and accrued liabilities	$	42,077	$	71,638

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Under Wyoming law, the Company is exposed to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. When such third parties are unable to fulfill their contractual obligations to the Company as provided for in purchase and sale agreements, landowners, as well as the Bureau of Land Management, may demand that the Company perform such activities.

Revenue Recognition. All of the Company’s sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company’s contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company’s contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company’s contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of June 30, 2020, the Company had open contracts with customers with terms of 1 month to 17 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The Company’s contracts with customers typically require payment within one month of delivery.

Under the Company’s contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of

these contracts compensate the Company for the value of the residue gas and NGLs at current market prices for each product. The Company’s oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the Company’s oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and therefore are recorded in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by the Company. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances were not significant in the periods presented.

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. A valuation allowance is recorded if it is more likely than not that all or some portion of the Company’s deferred tax assets will not be realized. The Company regularly assesses the realizability of the deferred tax assets considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine if a valuation allowance is required. Changes to the Company’s development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors including changes in tax law could change the valuation allowance in future periods, resulting in recognition of a tax expense or benefit.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of June 30, 2020.

Comprehensive Income. The Company has no elements of other comprehensive income, therefore, the Company’s net income (loss) on the Unaudited Consolidated Statements of Operations represents comprehensive income.

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The Company was in a net loss position for the three and six months ended June 30, 2020 and 2019; therefore, all potentially dilutive securities were anti-dilutive.

The following table sets forth the calculation of basic and diluted income (loss) per share:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)
Net income (loss)	$	(67,628)	$	(1,910)	$	(1,083,267)	$	(98,139)
Basic weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Diluted weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Basic net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Diluted net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)

New Accounting Pronouncements. In April 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2022, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other affected transactions. The Company currently has only one contract, its credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update has an effective period of March 12, 2020 through December 31, 2022 and allows for elections to be made by the Company in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications for that Topic or Industry Subtopic. The Company does not believe the standard will have a material impact on the Company’s financial statements.

In August 2018, the FASB issued ASU 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments, Credit Losses. The objective of this update is to amend current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”)) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 was effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures and financial statements.

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Supplemental Disclosures of Cash Flow Information

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Disclosures of Cash Flow Information

Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Cash paid for interest	$	27,635	$	26,689
Cash paid for income taxes	—		—
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases	873		595
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)(2)	777		14,955
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties	11,746		87,109
Change in asset retirement obligations, net of disposals	(12)		(5,022)
Retirement of treasury stock	(654)		(1,506)
Properties exchanged in non-cash transactions	4,753		4,561

(1)Excludes the reclassifications of lease incentives and deferred rent balances.

(2)The six months ended June 30, 2019 included $14.0 million of right-of-use assets established with the adoption of ASC 842, Leases, effective January 1, 2019.

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Long-Term Debt

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

The Company’s outstanding debt is summarized below:

		As of June 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Debt Issuance Costs		Carrying Amount		Principal		Debt Issuance Costs		Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	175,000	$	—	$	175,000	$	140,000	$	—	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,954)		348,046		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,373)		271,627		275,000		(3,717)		271,283
Total Long-Term Debt		$	800,000	$	(5,327)	$	794,673	$	765,000	$	(6,089)	$	758,911

Amended Credit Facility

On May 21, 2020, the Company entered into an amendment to the fourth amended and restated credit facility (the “Amended Credit Facility”), which decreased the aggregate elected commitment amount and the borrowing base from $500.0 million to $300.0 million, increased the applicable margins for interest and commitment fee rates and added provisions requiring the availability under the Amended Credit Facility to be at least $50.0 million and the Company’s weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. The Company had $175.0 million and $140.0 million outstanding under the Amended Credit Facility as of June 30, 2020 and December 31, 2019, respectively. As credit support for future payments under a contractual obligation, a $21.7 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity under the Amended Credit Facility as of June 30, 2020 to $53.3 million after taking into account the $50.0 million availability requirement. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if the Company has more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because the Company’s 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

As of May 21, 2020, interest rates on outstanding loans under the Amended Credit Facility are either adjusted LIBOR plus applicable margins of 2.5% to 3.5% or an alternate base rate, which is generally the prime rate, plus applicable margins of 1.5% to 2.5%, and the unused commitment fee is 0.5%. The applicable margins and the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Amended Credit Facility was 2.7% and 4.2% for the three months ended June 30, 2020 and 2019, respectively, and 3.0% and 4.1% for the six months ended June 30, 2020 and 2019, respectively.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from the reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt.

The Company has financial covenants associated with its Amended Credit Facility that are measured each fiscal quarter. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. However, if current market conditions continue, the Company may not be able to maintain compliance with these financial covenants. In particular, the Company may breach the debt-to-EBITDAX ratio and the current ratio covenants in the Amended Credit Facility in the latter part of 2021. Further, if the Company’s independent auditor were to include an explanatory paragraph regarding the Company’s ability to continue as a “going concern” in the auditors’ report on the Company’s financial statements for the year ending December 31, 2020, this would also cause a default under the Amended Credit Facility. If a covenant breach occurs or is likely, the Company may attempt to obtain a waiver from the lenders under the Amended Credit Facility, seek to amend the terms of the Amended Credit Facility to prevent the breach or seek to obtain alternative financing to repay the Amended Credit Facility balance outstanding. If these efforts are unsuccessful, all or a portion of the amount borrowed under the Amended Credit Facility could become due, and cross-defaults could occur under the Company’s senior notes and the Company may not have other sources of capital to repay the amounts due.

Senior Notes

The issuer of the 7.0% Senior Notes and the 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett), or Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the Merger, HighPoint Resources Corporation, or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. In addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of the Subsidiary Issuer on August 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. The Company has no additional subsidiaries or non-guarantor subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor. HighPoint Operating Corporation is currently in compliance with all covenants and has complied with all covenants since issuance.

Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

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Asset Retirement Obligations

6 Months Ended

Jun. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2020 is as follows (in thousands):

As of December 31, 2019	$	25,709
Liabilities incurred	488
Liabilities settled	(766)
Disposition of properties	(143)
Accretion expense	872
Revisions to estimate	409
As of June 30, 2020	$	26,569
Less: Current asset retirement obligations	2,619
Long-term asset retirement obligations	$	23,950

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Fair Value Measurements

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Fair value is defined as the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (exit price). The Company uses market data or assumptions that market participants would use in pricing the asset or liability, including assumptions about risk. These inputs can be readily observable, market corroborated or generally unobservable. A fair value hierarchy was established that prioritizes the inputs used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements).

Level 1 – Quoted prices are available in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

Level 2 – Quoted prices are available in active markets for similar assets or liabilities and in non-active markets for identical or similar instruments. Model-derived valuations have inputs that are observable or whose significant value drivers are observable. These models are primarily industry-standard models that consider various assumptions, including quoted forward prices for commodities, time value, volatility factors and current market and contractual prices for the underlying instruments, as well as other relevant economic measures. Substantially all of these assumptions are observable in the marketplace throughout the full term of the instrument, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace.

Level 3 – Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management’s best estimate of fair value. At each balance

sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are measured at fair value on a recurring basis in the Company’s Unaudited Consolidated Balance Sheets. The following methods and assumptions were used to estimate the fair values:

Cash equivalents – The highly liquid cash equivalents are recorded at fair value. Carrying value approximates fair value, which represents a Level 1 input.

Deferred compensation plan – The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in other current and other long-term assets in the Unaudited Consolidated Balance Sheets. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

Commodity derivatives – The fair value of crude oil, natural gas and NGL swaps and cashless collars are valued based on an income approach using various assumptions, such as quoted forward prices for commodities and time value factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are, therefore, designated as Level 2 inputs. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. The Company currently utilizes an independent third party to perform the valuation.

The commodity derivatives have been adjusted for non-performance risk. For applicable financial assets carried at fair value, the credit standing of the counterparties is analyzed and factored into the fair value measurement of those assets. In addition, the fair value measurement of a liability has been adjusted to reflect the nonperformance risk of the Company.

The following tables set forth by level within the fair value hierarchy the Company’s non-financial assets and liabilities that were measured at fair value on a recurring basis in the Unaudited Consolidated Balance Sheets.

	Level 1		Level 2		Level 3		Total
	(in thousands)
As of June 30, 2020
Financial Assets
Deferred compensation plan	$	1,167	$	—	$	—	$	1,167
Commodity derivatives	—		91,150		—		91,150
Financial Liabilities
Commodity derivatives	—		3,368		—		3,368
As of December 31, 2019
Financial Assets
Deferred compensation plan	$	2,033	$	—	$	—	$	2,033
Commodity derivatives	—		8,890		—		8,890
Financial Liabilities
Commodity derivatives	—		10,056		—		10,056

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Certain assets and liabilities are measured at fair value on a nonrecurring basis in the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Oil and gas properties – Proved oil and natural gas properties are evaluated for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever the Company concludes the carrying value may not be recoverable, the Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on its development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation

deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future net revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the three months ended March 31, 2020, the Company’s proved oil and gas properties with a carrying value of $1.7 billion were reduced to a fair value of $0.5 billion, resulting in an impairment of $1.2 billion which was included in impairment and abandonment expense on the Unaudited Statement of Operations for the three months ended March 31, 2020. For the three months ended March 31, 2020, the Company contracted with an independent third party to assist with the Company’s determination of fair value associated with its proved oil and gas properties. Through the use of the Company’s production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the PDP and PDN reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the PUD reserves. The following table includes quantitative information about the significant unobservable inputs, categorized within Level 3 of the fair value hierarchy, that were used in the fair value measurement.

Level 3 Unobservable Inputs	As of March 31, 2020
Price (1)
Oil (per Bbl)	$29 to $60
Gas (per MMbtu)	$2.03 to $2.52
NGL (percentage of oil price)	24% to 31%
Reserve adjustment factors
PDP	100%
PDN	95%
Discount rate	11%

(1)These prices were adjusted for location and quality differentials.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters. During the three months ended March 31, 2020, due to substantial commodity price declines, certain unproved oil and gas properties with a carrying value of $256.0 million were reduced to a fair value of $179.7 million, resulting in an impairment of $76.3 million which was included in impairment and abandonment expense on the Unaudited Statement of Operations for the three months ended March 31, 2020. For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company’s determination of fair value of the Company’s unproved oil and gas properties. The third party used the market approach utilizing sales prices of comparable properties to determine the fair value of the unproved oil and gas properties.

Additional Fair Value Disclosures

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The estimated fair value of the 7.0% Senior Notes was approximately $286.1 million and $335.0 million as of June 30, 2020 and December 31, 2019, respectively. The estimated fair value of the 8.75% Senior Notes was approximately $147.1 million and $251.2 million as of June 30, 2020 and December 31, 2019, respectively. The fair values of the Company’s fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility. The recorded value of the Amended Credit Facility is not materially different from its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company’s borrowing base utilization. The Amended Credit Facility had a balance of $175.0 million as of June 30, 2020 and $140.0 million as of December 31, 2019. The fair value measurements for the Amended Credit Facility represent Level 2 inputs.

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Derivative Instruments

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and swaption contracts related to the sale of a portion of the Company’s production. A swap allows the Company to receive a fixed price for its production and pay a variable market price to the counterparty. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. The Company has also entered into crude oil swaps to fix the differential in pricing between the NYMEX WTI calendar month average and the physical crude delivery month (“oil roll swaps”). The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.

All derivative instruments, other than those that meet the normal purchase and normal sale exception, as mentioned above, are recorded at fair value and included on the Unaudited Consolidated Balance Sheets as assets or liabilities. The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented on the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of June 30, 2020
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	73,466	$	(1,230)	$	72,236
Derivative assets (noncurrent)	17,684		(2,138)		15,546
Total derivative assets	$	91,150	$	(3,368)	$	87,782
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(1,230)	$	1,230	$	—
Other noncurrent liabilities	(2,138)		2,138		—
Total derivative liabilities	$	(3,368)	$	3,368	$	—
	As of December 31, 2019
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	8,477	$	(4,561)	$	3,916
Derivative assets (noncurrent)	413		(413)		—
Total derivative assets	$	8,890	$	(4,974)	$	3,916
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(8,972)	$	4,561	$	(4,411)
Other noncurrent liabilities	(1,084)		413		(671)
Total derivative liabilities	$	(10,056)	$	4,974	$	(5,082)

(1)Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

As of June 30, 2020, the Company had swap and swaption contracts in place to hedge the following volumes for the periods indicated:

	July – December 2020			For the year 2021			For the year 2022
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps
Oil (Bbls)	2,760,000	$	56.59	3,098,000	$	54.30	—	$	—
Natural Gas (MMbtu)	3,680,000	$	1.83	5,790,000	$	2.13	—	$	—
Oil Roll Swaps (1)
Oil (Bbls)	276,500	$	(1.47)	—	—		—	—
Swaptions
Oil (Bbls)	—	$	—	—	$	—	1,092,000	$	55.08

(1)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

The Company’s derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with eight different counterparties as of June 30, 2020. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

It is the Company’s policy to enter into derivative contracts with counterparties that are lenders in the Amended Credit Facility, affiliates of lenders in the Amended Credit Facility or potential lenders in the Amended Credit Facility. The Company’s derivative contracts are documented using an industry standard contract known as a Schedule to the Master Agreement and International Swaps and Derivative Association, Inc. (“ISDA”) Master Agreement or other contracts. Typical terms for these contracts include credit support requirements, cross default provisions, termination events and set-off provisions. The Company is not required to provide any credit support to its counterparties other than cross collateralization with the properties securing the Amended Credit Facility. The Company has set-off provisions in its derivative contracts with lenders under its Amended Credit Facility which, in the event of a counterparty default, allow the Company to set-off amounts owed to the defaulting counterparty under the Amended Credit Facility or other obligations against monies owed to the Company under derivative contracts. Where the counterparty is not a lender under the Company’s Amended Credit Facility, the Company may not be able to set-off amounts owed by the Company under the Amended Credit Facility, even if such counterparty is an affiliate of a lender under such facility. The Company does not have any derivative balances that are offset by cash collateral.

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Income Taxes

6 Months Ended

Jun. 30, 2020

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB’s rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and six months ended June 30, 2020 and 2019, the Company had no uncertain tax positions.

The Company’s policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company’s income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and six months ended June 30, 2020 and 2019.

Income tax benefit for the three and six months ended June 30, 2020 and 2019 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation, state income taxes, and for 2020, the

effect of deferred tax asset valuation allowances. For the three and six months ended June 30, 2020, the Company recognized zero and $95.3 million of income tax benefit, respectively. For the three and six months ended June 30, 2019, the Company recognized $0.1 million of income tax expense and $29.6 million of income tax benefit, respectively. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. For the three and six months ended June 30, 2020, the Company determined that there would not be sufficient future taxable income to use existing deferred tax assets and has recorded a valuation allowance against the existing net deferred tax assets. For the six months ended June 30, 2020, the Company has recorded a deferred tax liability of $2.1 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. 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 their expiration.

In response to the COVID-19 pandemic, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) on March 27, 2020. Several of the provisions included in the CARES Act apply to the Company. The primary impact is the accelerated refundability of the Company’s $1.4 million income tax receivable related to minimum tax credit carryforwards to 2019. The depreciable lives related to 2018 and 2019 qualified improvement property will be adjusted and result in accelerated tax depreciation. In addition, the CARES Act temporarily suspends the 80% income limitation for net operating losses generated and utilized in years beginning prior to January 1, 2021.

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs

6 Months Ended

Jun. 30, 2020

Share-based Payment Arrangement [Abstract]

Equity Incentive Compensation Plans and Other Long-term Incentive Programs

Equity Incentive Compensation Plans and Other Long-term Incentive Programs

The Company maintains various stock-based compensation plans and other employee benefits as discussed below. Stock-based compensation is measured at the grant date based on the value of the awards, and the fair value is recognized on a straight-line basis over the requisite service period (usually the vesting period). Nonvested shares of common stock generally vest ratably over a three year service period, and nonvested shares of common stock units vest over a one year service period. Cash-based compensation is measured at fair value at each reporting date and is recognized on a straight-line basis over the requisite service period (usually the vesting period). Cash-based awards generally have a cliff vest of three years.

The following table presents the long-term equity and cash incentive compensation related to awards for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Nonvested common stock (1)	$	1,150	$	1,533	$	2,300	$	3,329
Nonvested common stock units (1)	202		318		482		612
Nonvested performance cash units (2)(3)	198		445		(776)		1,077
Total	$	1,550	$	2,296	$	2,006	$	5,018

(1)Unrecognized compensation expense as of June 30, 2020 was $5.1 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.8 years.

(2)The nonvested performance-based cash units are accounted for as liability awards with $0.3 million and $1.2 million in other noncurrent liabilities as of June 30, 2020 and December 31, 2019, respectively, in the Unaudited Consolidated Balance Sheets.

(3)Liability awards are fair valued at each reporting date. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Nonvested Equity and Cash Awards. The following tables present the equity and cash awards granted pursuant to the Company’s various stock compensation plans. A summary of the Company’s nonvested common stock awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at April 1,	3,531,812	$	2.10	3,431,780	$	3.90
Granted	—	—		6,000	2.66
Vested	(112,677)	4.26		(30,031)	5.81
Forfeited or expired	(250,431)	1.52		(1,615)	7.14
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at January 1,	2,968,497	$	3.81	2,912,166	$	5.27
Granted	2,028,617	1.14		1,841,700	2.64
Vested	(1,568,491)	4.25		(1,329,630)	5.20
Forfeited or expired	(259,919)	1.59		(18,102)	4.96
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88

A summary of the Company’s nonvested common stock unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at April 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		628,380	1.87
Vested	(638,355)	2.63		(143,514)	5.77
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at January 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		643,084	1.88
Vested	(638,355)	2.63		(158,218)	5.44
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27

A summary of the Company’s nonvested performance-based cash unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at April 1,	6,096,230			2,868,634
Forfeited or expired	(656,430)			—
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at January 1,	2,576,062			909,585
Granted	3,569,434			2,026,521
Forfeited or expired	(705,696)			(67,472)
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82

Performance Cash Program

2020 Program. In February 2020, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the “2020 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2023, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2022, will be the Company’s total shareholder return (“TSR”) based on a matrix measurement of (1) the Company’s absolute performance and (2) the Company’s ranking relative to a defined peer group’s individual TSRs (“Relative TSR”). The Company’s absolute performance is measured against the December 31, 2019 closing share price of $1.69. For the portion of the program based on absolute performance, the payout will be equal to the Company’s absolute TSR up to 100%, which is the maximum payout for this portion. For the portion of the program based on relative performance (i) if the Company’s Relative TSR is less than 30%, the payout is zero and (ii) if the Company’s Relative TSR is 30% or greater, the payout is equal to the Company’s percentile rank up to 100% of the original grant. The Company’s combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant.

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Leases

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Leases

Leases

A contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. For all leases, other than those that qualify for the short-term recognition exemption, the Company recognizes as of the lease commencement date on the balance sheet a liability for its obligation related to the lease and a corresponding asset representing the Company’s right to use the underlying asset over the period of use. The Company currently has leases for office space and other equipment, all of which are classified as operating leases.

The Company’s leases have remaining terms of up to eight years. Certain lease agreements contain options to extend or early terminate the agreement. These options are used to calculate right-of-use asset and lease liability balances when it is reasonably certain that the Company will exercise these options. The discount rate used to calculate the present value of the future minimum lease payments is the Company’s incremental borrowing rate.

The Company elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, recognize the lease payments in the income statement on a straight-line basis over the lease term. The Company also elected, for certain classes of underlying assets, to combine lease and non-lease components. Therefore, the Company elected to combine lease and non-lease components for drilling rig and gathering system asset classes. These assets are not reported on the Unaudited Consolidated Balance Sheets as the Company’s lease contracts for drilling rigs are currently classified as short-term and the Company’s lease contract for a gathering system includes variable payments.

For the three and six months ended June 30, 2020 and 2019, lease cost were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Lease Cost	2020		2019		2020		2019
	(in thousands)
Operating lease cost (1)(3)	$	529	$	569	$	1,039	$	1,117
Short-term lease cost (2)(3)	789		4,167		3,052		10,386
Variable lease cost (4)	373		—		693		—
Total lease cost	$	1,691	$	4,736	$	4,784	$	11,503

(1)Operating lease cost was primarily included in general and administrative expense or lease operating expense on the Unaudited Consolidated Statements of Operations.

(2)Short-term lease cost primarily includes leases for drilling rigs, which were capitalized to property, plant and equipment on the Unaudited Consolidated Balance Sheets.

(3)A portion of the operating lease cost and a majority of the short-term lease cost represent gross amounts that the Company was financially committed to pay. However, the Company recorded in the financial statements its proportionate share based on the Company’s working interest, which varies from property to property.

(4)Variable lease cost is related to a gathering agreement and is included in oil, gas, and NGL production on the Unaudited Consolidated Statements of Operations.

Supplemental balance sheet information related to leases as of June 30, 2020 and December 31, 2019, were as follows:

Operating Leases	As of June 30, 2020			As of December 31, 2019
	(in thousands)
Right-of-use assets (1)	$	9,906		$	9,287
Accumulated amortization (2)	(1,621)			(1,142)
Total right-of-use assets, net (3)	$	8,285		$	8,145
Current lease liabilities (4)	(1,954)			(1,287)
Noncurrent lease liabilities (5)	(12,834)			(13,195)
Total lease liabilities (3)	$	(14,788)		$	(14,482)
Weighted average remaining lease term
Operating leases (in years)	7.3			7.8
Weighted average discount rate
Operating leases	5.6		%	5.6		%

(1)Included in furniture, equipment and other in the Unaudited Consolidated Balance Sheets.

(2)Included in accumulated depreciation, depletion, amortization and impairment in the Unaudited Consolidated Balance Sheets.

(3)The difference between the right-of-use assets and total lease liabilities is primarily related to lease incentives and deferred rent balances, which were required to be netted against the right-of-use assets as of the ASC 842 implementation date of January 1, 2019.

(4)Included in accounts payable and accrued liabilities in the Unaudited Consolidated Balance Sheets.

(5)Included in other noncurrent liabilities in the Unaudited Consolidated Balance Sheets.

Maturities of lease liabilities as of June 30, 2020 and December 31, 2019 were as follows:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
2020	$	1,377	$	2,056
2021	2,635		2,355
2022	2,324		2,044
2023	2,101		2,024
2024	2,078		2,078
Thereafter	7,576		7,577
Total	$	18,091	$	18,134
Less: Interest	(3,303)		(3,652)
Present value of lease liabilities	$	14,788	$	14,482

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Commitments and Contingencies

6 Months Ended

Jun. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and Contingencies

Firm Transportation Agreements. The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.

The Company is party to one firm pipeline transportation contract to provide capacity on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges from May 2020 through April 2025 regardless of the amount of pipeline capacity utilized by the Company.

The amounts in the table below represent the Company’s future minimum transportation charges:

	As of June 30, 2020
	(in thousands)
2020	$	12,732
2021	19,777
2022	13,064
2023	14,600
2024	14,640
Thereafter	4,800
Total	$	79,613

Gas Gathering and Processing Agreements. The Company is party to one minimum volume commitment and two reimbursement obligations. The minimum volume commitment requires the Company to deliver a minimum volume of natural gas to a midstream entity for gathering and processing. The contract requires the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The reimbursement obligations require the Company to pay monthly gathering and processing fees per Mcf of production to reimburse midstream entities for their costs to construct gas gathering and processing facilities. If the costs are not reimbursed by the Company via the monthly gathering and processing fees, the Company must pay the difference. The amounts in the table below represent the Company’s future minimum charges under both types of agreements:

	As of June 30, 2020
	(in thousands)
2020	$	1,089
2021	5,268
Thereafter	—
Total	$	6,357

Other Commitments. The Company has one drilling commitment with a joint interest partner that requires the Company to drill and complete two wells by July 2022 and three wells by July 2023. If the drilling commitment is not met, the Company must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. The Company is party to two minimum volume commitments for fresh water. The minimum volume commitments require the Company to purchase a minimum volume of fresh water from a water supplier. The contracts require the Company pay a fee associated with the contracted volumes regardless of the amount delivered. The Company also has non-cancellable agreements for information technology services. Future minimum annual payments under these agreements are as follows:

	As of June 30, 2020
	(in thousands)
2020	$	1,098
2021	1,285
2022 (1)	11,485
2023 (1)	16,285
Thereafter	—
Total	$	30,153

(1)Includes $10.2 million in 2022 and $15.3 million in 2023 related to a drilling commitment.

Litigation. The Company is subject to litigation, claims and governmental and regulatory proceedings arising in the ordinary course of business. It is the opinion of the Company’s management that current claims and litigation involving the Company are not likely to have a material adverse effect on its Unaudited Consolidated Balance Sheet, Cash Flows or Statements of Operations, other than the following.

Sterling Energy Investments LLC v. HighPoint Operating Corporation, 2020CV32034, District Court in Denver, Colorado. On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint Operating Corporation, a subsidiary of the Company, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017, by and between HighPoint Operating Corporation and Sterling. Sterling alleges that HighPoint Operating Corporation breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. The Company vigorously denies Sterling’s claims. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, the Company filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Gathering Agreement. The Company is seeking monetary damages in an amount not yet specified.

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Summary of Significant Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company’s interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company’s Annual Report on Form 10-K for the year ended December 31, 2019 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. 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 Annual Report on Form 10-K.

Use of Estimates

Use of Estimates. In the course of preparing the Company’s financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure 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 initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, right-of-use assets and lease liabilities, deferred income taxes, the timing of dry hole costs, impairments of proved and unproved oil and gas properties and fair values of derivative instruments and stock-based payment awards. Further, these estimates and other factors, including those outside of the Company’s control, such as the impact of lower commodity prices, may have a significant adverse impact to the Company’s business, financial condition, results of operations and cash flows.

Oil and Gas Properties

Oil and Gas Properties. The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Proved properties	$	721,174	$	725,964
Wells and related equipment and facilities	1,910,527		1,805,136
Support equipment and facilities	105,397		99,540
Materials and supplies	11,944		13,489
Total proved oil and gas properties	$	2,749,042	$	2,644,129
Unproved properties	182,605		265,387
Wells and facilities in progress	60,704		92,406
Total unproved oil and gas properties, excluded from amortization	$	243,309	$	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,224,428)		(958,475)
Total oil and gas properties, net	$	767,923	$	2,043,447

The Company reviews proved oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. The Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on an analysis of quantitative and qualitative factors existing as of the balance sheet date including the Company’s development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures, income taxes and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, the Organization of Petroleum Exporting Countries (“OPEC”), along with non-OPEC oil-producing countries (collectively known as “OPEC+”), initiated discussions to lower production to support energy prices. With OPEC+ unable to agree on cuts, crude oil prices declined to an average of $30.45 per barrel for the month of March 2020, compared to an average of $59.80 per barrel for the month of December 2019. These events led to a decline in the recoverability of the carrying value of the Company’s oil and gas properties during the three months ended March 31, 2020. Since the carrying amount of the oil and gas properties was no longer recoverable, the Company impaired the carrying value to fair value. Therefore, the Company recognized non-cash impairment

charges during the three months ended March 31, 2020, which were included within impairment and abandonment expense in the Unaudited Consolidated Statements of Operations.

For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company’s determination of fair value associated with the Company’s proved and unproved oil and gas properties. Through the use of the Company’s production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the proved developed producing (“PDP”) and proved developed non-producing (“PDN”) reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the proved undeveloped (“PUD”), probable (“PROB”) and possible (“POSS”) reserves. The Company’s impairment and abandonment expense for the three and six months ended June 30, 2020 and 2019 is summarized below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Impairment of proved oil and gas properties	$	—	$	—	$	1,188,566	$	—
Impairment of unproved oil and gas properties	—		—		76,298		—
Abandonment expense	810		995		1,372		1,317
Total impairment and abandonment expense	$	810	$	995	$	1,266,236	$	1,317

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities. Accounts payable and accrued liabilities are comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Accrued drilling, completion and facility costs	$	12,957	$	25,667
Accrued lease operating, gathering, transportation and processing expenses	7,364		8,046
Accrued general and administrative expenses	6,910		6,612
Accrued interest payable	6,681		6,832
Trade payables	3,951		17,488
Operating lease liability	1,954		1,287
Other	2,260		5,706
Total accounts payable and accrued liabilities	$	42,077	$	71,638

Environmental Liabilities

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Under Wyoming law, the Company is exposed to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. When such third parties are unable to fulfill their contractual obligations to the Company as provided for in purchase and sale agreements, landowners, as well as the Bureau of Land Management, may demand that the Company perform such activities.

Revenue Recognition

Revenue Recognition. All of the Company’s sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company’s contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company’s contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company’s contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of June 30, 2020, the Company had open contracts with customers with terms of 1 month to 17 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The Company’s contracts with customers typically require payment within one month of delivery.

Under the Company’s contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of

these contracts compensate the Company for the value of the residue gas and NGLs at current market prices for each product. The Company’s oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the Company’s oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and therefore are recorded in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by the Company. If the Company’s aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances were not significant in the periods presented.

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities. The Company periodically uses derivative financial instruments to achieve a more predictable cash flow from its oil, natural gas and NGL sales by reducing its exposure to price fluctuations. Derivative instruments are recorded at fair market value and are included in the Unaudited Consolidated Balance Sheets as assets or liabilities.

Income Taxes

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. A valuation allowance is recorded if it is more likely than not that all or some portion of the Company’s deferred tax assets will not be realized. The Company regularly assesses the realizability of the deferred tax assets considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine if a valuation allowance is required. Changes to the Company’s development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors including changes in tax law could change the valuation allowance in future periods, resulting in recognition of a tax expense or benefit.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of June 30, 2020.

Comprehensive Income

Comprehensive Income. The Company has no elements of other comprehensive income, therefore, the Company’s net income (loss) on the Unaudited Consolidated Statements of Operations represents comprehensive income.

Earnings/Loss Per Share

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The Company was in a net loss position for the three and six months ended June 30, 2020 and 2019; therefore, all potentially dilutive securities were anti-dilutive.

The following table sets forth the calculation of basic and diluted income (loss) per share:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)
Net income (loss)	$	(67,628)	$	(1,910)	$	(1,083,267)	$	(98,139)
Basic weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Diluted weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Basic net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Diluted net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)

New Accounting Pronouncements

New Accounting Pronouncements. In April 2020, the Financial Accounting Standards Board (“FASB”) issued Accounting Standards Update (“ASU”) 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate (“LIBOR”) by December 31, 2022, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other affected transactions. The Company currently has only one contract, its credit facility, that may be impacted by this ASU. Modifications of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update has an effective period of March 12, 2020 through December 31, 2022 and allows for elections to be made by the Company in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications for that Topic or Industry Subtopic. The Company does not believe the standard will have a material impact on the Company’s financial statements.

In August 2018, the FASB issued ASU 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures.

In June 2016, the FASB issued ASU 2016-13, Financial Instruments, Credit Losses. The objective of this update is to amend current impairment guidance by adding an impairment model (known as the current expected credit loss model (“CECL”)) that is based on expected losses rather than incurred losses. Under the new guidance, an entity recognizes as an allowance its estimate of lifetime expected credit losses, which the FASB believes will result in more timely recognition of such losses. ASU 2016-13 was effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard was adopted on January 1, 2020 and did not have a material impact on the Company’s disclosures and financial statements.

Leases

A contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. For all leases, other than those that qualify for the short-term recognition exemption, the Company recognizes as of the lease commencement date on the balance sheet a liability for its obligation related to the lease and a corresponding asset representing the Company’s right to use the underlying asset over the period of use.

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Summary of Significant Accounting Policies (Tables)

6 Months Ended

Jun. 30, 2020

Accounting Policies [Abstract]

Schedule of Accounts Receivable

Accounts receivable is comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Oil, gas and NGL sales	$	32,383	$	50,171
Due from joint interest owners (1)	23,796		9,551
Other	3,129		2,419
Allowance for doubtful accounts	(31)		(21)
Total accounts receivable	$	59,277	$	62,120

(1)Includes $12.9 million associated with one joint interest partner. In the event of nonpayment, the Company expects to net the outstanding amount against certain revenues payable to this joint interest partner.

Net Capitalized Costs and Associated Accumulated DD&A and Non Cash Impairments

The following table sets forth the net capitalized costs and associated accumulated DD&A and non-cash impairments relating to the Company’s oil, natural gas and NGL producing activities:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Proved properties	$	721,174	$	725,964
Wells and related equipment and facilities	1,910,527		1,805,136
Support equipment and facilities	105,397		99,540
Materials and supplies	11,944		13,489
Total proved oil and gas properties	$	2,749,042	$	2,644,129
Unproved properties	182,605		265,387
Wells and facilities in progress	60,704		92,406
Total unproved oil and gas properties, excluded from amortization	$	243,309	$	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,224,428)		(958,475)
Total oil and gas properties, net	$	767,923	$	2,043,447

Schedule Of Noncash Impairment Charges

The Company’s impairment and abandonment expense for the three and six months ended June 30, 2020 and 2019 is summarized below:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Impairment of proved oil and gas properties	$	—	$	—	$	1,188,566	$	—
Impairment of unproved oil and gas properties	—		—		76,298		—
Abandonment expense	810		995		1,372		1,317
Total impairment and abandonment expense	$	810	$	995	$	1,266,236	$	1,317

Accounts Payable and Accrued Liabilities

Accounts payable and accrued liabilities are comprised of the following:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
Accrued drilling, completion and facility costs	$	12,957	$	25,667
Accrued lease operating, gathering, transportation and processing expenses	7,364		8,046
Accrued general and administrative expenses	6,910		6,612
Accrued interest payable	6,681		6,832
Trade payables	3,951		17,488
Operating lease liability	1,954		1,287
Other	2,260		5,706
Total accounts payable and accrued liabilities	$	42,077	$	71,638

Calculation of Basic and Diluted Earnings (Loss) Per Share

The following table sets forth the calculation of basic and diluted income (loss) per share:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands, except per share amounts)
Net income (loss)	$	(67,628)	$	(1,910)	$	(1,083,267)	$	(98,139)
Basic weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Diluted weighted-average common shares outstanding in period	211,895		210,377		211,503		210,156
Basic net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)
Diluted net income (loss) per common share	$	(0.32)	$	(0.01)	$	(5.12)	$	(0.47)

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Supplemental Disclosures of Cash Flow Information (Tables)

6 Months Ended

Jun. 30, 2020

Supplemental Cash Flow Elements [Abstract]

Supplemental Cash Flow Information

Supplemental cash flow information is as follows:

	Six Months Ended June 30,
	2020		2019
	(in thousands)
Cash paid for interest	$	27,635	$	26,689
Cash paid for income taxes	—		—
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases	873		595
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)(2)	777		14,955
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties	11,746		87,109
Change in asset retirement obligations, net of disposals	(12)		(5,022)
Retirement of treasury stock	(654)		(1,506)
Properties exchanged in non-cash transactions	4,753		4,561

(1)Excludes the reclassifications of lease incentives and deferred rent balances.

(2)The six months ended June 30, 2019 included $14.0 million of right-of-use assets established with the adoption of ASC 842, Leases, effective January 1, 2019.

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2020

Debt Disclosure [Abstract]

Outstanding Debt

The Company’s outstanding debt is summarized below:

		As of June 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Debt Issuance Costs		Carrying Amount		Principal		Debt Issuance Costs		Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	175,000	$	—	$	175,000	$	140,000	$	—	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,954)		348,046		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,373)		271,627		275,000		(3,717)		271,283
Total Long-Term Debt		$	800,000	$	(5,327)	$	794,673	$	765,000	$	(6,089)	$	758,911

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Asset Retirement Obligations (Tables)

6 Months Ended

Jun. 30, 2020

Asset Retirement Obligation Disclosure [Abstract]

Schedule of Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the six months ended June 30, 2020 is as follows (in thousands):

As of December 31, 2019	$	25,709
Liabilities incurred	488
Liabilities settled	(766)
Disposition of properties	(143)
Accretion expense	872
Revisions to estimate	409
As of June 30, 2020	$	26,569
Less: Current asset retirement obligations	2,619
Long-term asset retirement obligations	$	23,950

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Fair Value Measurements (Tables)

6 Months Ended

Jun. 30, 2020

Fair Value Disclosures [Abstract]

Fair Value, Balance Sheet Grouping

The following tables set forth by level within the fair value hierarchy the Company’s non-financial assets and liabilities that were measured at fair value on a recurring basis in the Unaudited Consolidated Balance Sheets.

	Level 1		Level 2		Level 3		Total
	(in thousands)
As of June 30, 2020
Financial Assets
Deferred compensation plan	$	1,167	$	—	$	—	$	1,167
Commodity derivatives	—		91,150		—		91,150
Financial Liabilities
Commodity derivatives	—		3,368		—		3,368
As of December 31, 2019
Financial Assets
Deferred compensation plan	$	2,033	$	—	$	—	$	2,033
Commodity derivatives	—		8,890		—		8,890
Financial Liabilities
Commodity derivatives	—		10,056		—		10,056

Fair Value, Assets Measured on Nonrecurring Basis, Level 3 Unobservable Inputs

The following table includes quantitative information about the significant unobservable inputs, categorized within Level 3 of the fair value hierarchy, that were used in the fair value measurement.

Level 3 Unobservable Inputs	As of March 31, 2020
Price (1)
Oil (per Bbl)	$29 to $60
Gas (per MMbtu)	$2.03 to $2.52
NGL (percentage of oil price)	24% to 31%
Reserve adjustment factors
PDP	100%
PDN	95%
Discount rate	11%

(1)These prices were adjusted for location and quality differentials.

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2020

Derivative Instruments and Hedging Activities Disclosures [Line Items]

Fair Value Amounts of Derivative Instruments

The following table summarizes the location, as well as the gross and net fair value amounts, of all derivative instruments presented on the Unaudited Consolidated Balance Sheets as of the dates indicated.

	As of June 30, 2020
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	73,466	$	(1,230)	$	72,236
Derivative assets (noncurrent)	17,684		(2,138)		15,546
Total derivative assets	$	91,150	$	(3,368)	$	87,782
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(1,230)	$	1,230	$	—
Other noncurrent liabilities	(2,138)		2,138		—
Total derivative liabilities	$	(3,368)	$	3,368	$	—
	As of December 31, 2019
Balance Sheet	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Assets Presented in the Balance Sheet
	(in thousands)
Derivative assets (current)	$	8,477	$	(4,561)	$	3,916
Derivative assets (noncurrent)	413		(413)		—
Total derivative assets	$	8,890	$	(4,974)	$	3,916
	Gross Amounts of Recognized Liabilities		Gross Amounts Offset in the Balance Sheet (1)		Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(8,972)	$	4,561	$	(4,411)
Other noncurrent liabilities	(1,084)		413		(671)
Total derivative liabilities	$	(10,056)	$	4,974	$	(5,082)

(1)Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

Financial Instruments for Hedging Volumes

As of June 30, 2020, the Company had swap and swaption contracts in place to hedge the following volumes for the periods indicated:

	July – December 2020			For the year 2021			For the year 2022
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps
Oil (Bbls)	2,760,000	$	56.59	3,098,000	$	54.30	—	$	—
Natural Gas (MMbtu)	3,680,000	$	1.83	5,790,000	$	2.13	—	$	—
Oil Roll Swaps (1)
Oil (Bbls)	276,500	$	(1.47)	—	—		—	—
Swaptions
Oil (Bbls)	—	$	—	—	$	—	1,092,000	$	55.08

(1)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs (Tables)

6 Months Ended

Jun. 30, 2020

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Non-Cash Stock-Based Compensation Cost Related to Equity Awards

The following table presents the long-term equity and cash incentive compensation related to awards for the periods indicated:

	Three Months Ended June 30,				Six Months Ended June 30,
	2020		2019		2020		2019
	(in thousands)
Nonvested common stock (1)	$	1,150	$	1,533	$	2,300	$	3,329
Nonvested common stock units (1)	202		318		482		612
Nonvested performance cash units (2)(3)	198		445		(776)		1,077
Total	$	1,550	$	2,296	$	2,006	$	5,018

(1)Unrecognized compensation expense as of June 30, 2020 was $5.1 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.8 years.

(2)The nonvested performance-based cash units are accounted for as liability awards with $0.3 million and $1.2 million in other noncurrent liabilities as of June 30, 2020 and December 31, 2019, respectively, in the Unaudited Consolidated Balance Sheets.

(3)Liability awards are fair valued at each reporting date. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Nonvested Equity Shares

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Nonvested Share Activity

A summary of the Company’s nonvested common stock awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at April 1,	3,531,812	$	2.10	3,431,780	$	3.90
Granted	—	—		6,000	2.66
Vested	(112,677)	4.26		(30,031)	5.81
Forfeited or expired	(250,431)	1.52		(1,615)	7.14
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Awards	Shares	Weighted Average Grant Date Fair Value		Shares	Weighted Average Grant Date Fair Value
Outstanding at January 1,	2,968,497	$	3.81	2,912,166	$	5.27
Granted	2,028,617	1.14		1,841,700	2.64
Vested	(1,568,491)	4.25		(1,329,630)	5.20
Forfeited or expired	(259,919)	1.59		(18,102)	4.96
Outstanding at June 30,	3,168,704	2.07		3,406,134	3.88

Nonvested Performance Cash Units

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Nonvested Performance-based Units Activity

A summary of the Company’s nonvested performance-based cash unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at April 1,	6,096,230			2,868,634
Forfeited or expired	(656,430)			—
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units	Weighted Average Fair Value		Units	Weighted Average Fair Value
Outstanding at January 1,	2,576,062			909,585
Granted	3,569,434			2,026,521
Forfeited or expired	(705,696)			(67,472)
Outstanding at June 30,	5,439,800	$	0.30	2,868,634	$	1.82

Director

Share-based Compensation Arrangement by Share-based Payment Award [Line Items]

Schedule of Nonvested Share Activity

A summary of the Company’s nonvested common stock unit awards for the three and six months ended June 30, 2020 and 2019 is presented below:

	Three Months Ended June 30, 2020			Three Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at April 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		628,380	1.87
Vested	(638,355)	2.63		(143,514)	5.77
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27
	Six Months Ended June 30, 2020			Six Months Ended June 30, 2019
Nonvested Common Stock Unit Awards	Units	Weighted Average Grant Date Fair Value		Units	Weighted Average Grant Date Fair Value
Outstanding at January 1,	796,103	$	3.27	311,237	$	7.26
Granted	530,940	0.27		643,084	1.88
Vested	(638,355)	2.63		(158,218)	5.44
Forfeited or expired	(79,423)	0.25		—	—
Outstanding at June 30,	609,265	1.72		796,103	3.27

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Leases (Tables)

6 Months Ended

Jun. 30, 2020

Leases [Abstract]

Lease, Cost

For the three and six months ended June 30, 2020 and 2019, lease cost were as follows:

	Three Months Ended June 30,				Six Months Ended June 30,
Lease Cost	2020		2019		2020		2019
	(in thousands)
Operating lease cost (1)(3)	$	529	$	569	$	1,039	$	1,117
Short-term lease cost (2)(3)	789		4,167		3,052		10,386
Variable lease cost (4)	373		—		693		—
Total lease cost	$	1,691	$	4,736	$	4,784	$	11,503

(1)Operating lease cost was primarily included in general and administrative expense or lease operating expense on the Unaudited Consolidated Statements of Operations.

(2)Short-term lease cost primarily includes leases for drilling rigs, which were capitalized to property, plant and equipment on the Unaudited Consolidated Balance Sheets.

(3)A portion of the operating lease cost and a majority of the short-term lease cost represent gross amounts that the Company was financially committed to pay. However, the Company recorded in the financial statements its proportionate share based on the Company’s working interest, which varies from property to property.

(4)Variable lease cost is related to a gathering agreement and is included in oil, gas, and NGL production on the Unaudited Consolidated Statements of Operations.

Supplemental Balance Sheet Information, Leases

Supplemental balance sheet information related to leases as of June 30, 2020 and December 31, 2019, were as follows:

Operating Leases	As of June 30, 2020			As of December 31, 2019
	(in thousands)
Right-of-use assets (1)	$	9,906		$	9,287
Accumulated amortization (2)	(1,621)			(1,142)
Total right-of-use assets, net (3)	$	8,285		$	8,145
Current lease liabilities (4)	(1,954)			(1,287)
Noncurrent lease liabilities (5)	(12,834)			(13,195)
Total lease liabilities (3)	$	(14,788)		$	(14,482)
Weighted average remaining lease term
Operating leases (in years)	7.3			7.8
Weighted average discount rate
Operating leases	5.6		%	5.6		%

(1)Included in furniture, equipment and other in the Unaudited Consolidated Balance Sheets.

(2)Included in accumulated depreciation, depletion, amortization and impairment in the Unaudited Consolidated Balance Sheets.

(3)The difference between the right-of-use assets and total lease liabilities is primarily related to lease incentives and deferred rent balances, which were required to be netted against the right-of-use assets as of the ASC 842 implementation date of January 1, 2019.

(4)Included in accounts payable and accrued liabilities in the Unaudited Consolidated Balance Sheets.

(5)Included in other noncurrent liabilities in the Unaudited Consolidated Balance Sheets.

Lessee, Operating Lease, Liability, Maturity

Maturities of lease liabilities as of June 30, 2020 and December 31, 2019 were as follows:

	As of June 30, 2020		As of December 31, 2019
	(in thousands)
2020	$	1,377	$	2,056
2021	2,635		2,355
2022	2,324		2,044
2023	2,101		2,024
2024	2,078		2,078
Thereafter	7,576		7,577
Total	$	18,091	$	18,134
Less: Interest	(3,303)		(3,652)
Present value of lease liabilities	$	14,788	$	14,482

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Commitments and Contingencies (Tables)

6 Months Ended

Jun. 30, 2020

Commitments and Contingencies Disclosure [Abstract]

Gross Future Minimum Transportation Demand and Firm Processing Charges

The amounts in the table below represent the Company’s future minimum transportation charges:

	As of June 30, 2020
	(in thousands)
2020	$	12,732
2021	19,777
2022	13,064
2023	14,600
2024	14,640
Thereafter	4,800
Total	$	79,613

Schedule Of Gross Future Minimum Volume Charges

The amounts in the table below represent the Company’s future minimum charges under both types of agreements:

	As of June 30, 2020
	(in thousands)
2020	$	1,089
2021	5,268
Thereafter	—
Total	$	6,357

Other Commitments

Future minimum annual payments under these agreements are as follows:

	As of June 30, 2020
	(in thousands)
2020	$	1,098
2021	1,285
2022 (1)	11,485
2023 (1)	16,285
Thereafter	—
Total	$	30,153

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Summary of Significant Accounting Policies - Additional Information (Detail) $ in Millions	Jun. 30, 2020 USD ($)
Property, Plant and Equipment [Line Items]
Accounts Receivable, Due from One Joint Interest Partner	$ 12.9

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Summary of Significant Accounting Policies - Summary of Accounts Receivable (Detail) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts	$ (31)	$ (21)
Total accounts receivable	59,277	62,120
Oil, gas and NGL sales
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	32,383	50,171
Due from joint interest owners (1)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	23,796	9,551
Other
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable gross	$ 3,129	$ 2,419

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Summary of Significant Accounting Policies - Net Capitalized Costs and Associated Accumulated Depreciation, Depletion & Amortization and Non Cash Impairments (Detail) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Proved properties	$ 721,174	$ 725,964
Wells and related equipment and facilities	1,910,527	1,805,136
Support equipment and facilities	105,397	99,540
Materials and supplies	11,944	13,489
Total proved oil and gas properties	2,749,042	2,644,129
Unproved properties	182,605	265,387
Wells and facilities in progress	60,704	92,406
Total unproved oil and gas properties, excluded from amortization	243,309	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,224,428)	(958,475)
Total oil and gas properties, net	$ 767,923	$ 2,043,447

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Summary of Significant Accounting Policies - Non-cash Impairment Charges (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Schedule of Non-cash Impairment Charges [Line Items]
Abandonment expense	$ 810		$ 995	$ 1,372	$ 1,317
Impairment and abandonment expense	810		995	1,266,236	1,317
Unproved Oil and Gas Properties
Schedule of Non-cash Impairment Charges [Line Items]
Impairment of Oil and Gas Properties	0	$ 76,300	0	76,298	0
Proved Oil and Gas Properties
Schedule of Non-cash Impairment Charges [Line Items]
Impairment of Oil and Gas Properties	$ 0	$ 1,200,000	$ 0	$ 1,188,566	$ 0

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Summary of Significant Accounting Policies - Accounts Payable and Accrued Liabilities (Detail) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Accounting Policies [Abstract]
Accrued drilling, completion and facility costs	$ 12,957	$ 25,667
Accrued lease operating, gathering, transportation and processing expenses	7,364	8,046
Accrued general and administrative expenses	6,910	6,612
Accrued interest payable	6,681	6,832
Trade payables	3,951	17,488
Operating lease liability	1,954	1,287
Other	2,260	5,706
Total accounts payable and accrued liabilities	$ 42,077	$ 71,638

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Summary of Significant Accounting Policies - Revenue Recognition (Details)	6 Months Ended
	Jun. 30, 2020
Revenue from External Customer [Line Items]
Contract payment term	1 month
Minimum
Revenue from External Customer [Line Items]
Revenue contract term	1 month
Maximum
Revenue from External Customer [Line Items]
Revenue contract term	17 years

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Summary of Significant Accounting Policies - Calculation of Basic and Diluted Earnings (Loss) Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Accounting Policies [Abstract]
Net Income (Loss)	$ (67,628)	$ (1,910)	$ (1,083,267)	$ (98,139)
Basic weighted-average common shares outstanding in period (in shares)	211,894,790	210,377,152	211,503,310	210,155,678
Diluted weighted-average common shares outstanding in period (in shares)	211,894,790	210,377,152	211,503,310	210,155,678
Basic net income (loss) per common share (in dollars per share)	$ (0.32)	$ (0.01)	$ (5.12)	$ (0.47)
Diluted net income (loss) per common share (in dollars per share)	$ (0.32)	$ (0.01)	$ (5.12)	$ (0.47)

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Supplemental Disclosures of Cash Flow Information - Supplemental Cash Flow Information (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019
Supplemental Cash Flow Information [Abstract]
Cash paid for interest	$ 27,635	$ 26,689
Cash paid for income taxes	0	0
Cash paid for operating leases	873	595
Non-cash operating activities:
Operating leases	777	14,955
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties	11,746	87,109
Change in asset retirement obligations, net of disposals	(12)	(5,022)
Retirement of treasury stock	(654)	(1,506)
Properties exchanged in non-cash transactions	$ 4,753	$ 4,561

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Supplemental Disclosures of Cash Flow Information - Additional Information (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019	Jan. 01, 2019
Additional Cash Flow Elements and Supplemental Cash Flow Information [Abstract]
Right-of-use assets	$ 8,285	$ 8,145	$ 14,000

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Long-Term Debt - Outstanding Debt (Detail) - USD ($)	6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Principal	$ 800,000,000		$ 765,000,000
Debt Issuance Costs	(5,327,000)		(6,089,000)
Carrying Amount	$ 794,673,000		758,911,000
Amended Credit Facility
Debt Instrument [Line Items]
Maturity Date	Sep. 14, 2023
Principal	$ 175,000,000		140,000,000
Debt Issuance Costs	0		0
Carrying Amount	175,000,000		140,000,000
Line of credit facility, maximum borrowing capacity	$ 300,000,000.0	$ 500,000,000.0
7.0% Senior Notes
Debt Instrument [Line Items]
Maturity Date	Oct. 15, 2022
Principal	$ 350,000,000		350,000,000
Debt Issuance Costs	(1,954,000)		(2,372,000)
Carrying Amount	$ 348,046,000		347,628,000
Debt, stated interest rate	7.00%
8.75% Senior Notes
Debt Instrument [Line Items]
Maturity Date	Jun. 15, 2025
Principal	$ 275,000,000		275,000,000
Debt Issuance Costs	(3,373,000)		(3,717,000)
Carrying Amount	$ 271,627,000		$ 271,283,000
Debt, stated interest rate	8.75%

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Long-Term Debt - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Mar. 31, 2020	Dec. 31, 2019
Debt Instrument [Line Items]
Principal amount	$ 800,000,000		$ 800,000,000			$ 765,000,000
Weighted average interest rate	2.70%	4.20%	3.00%	4.10%
Minimum
Debt Instrument [Line Items]
Interest rate margin			2.50%
Revolving credit facility interest rate percent above LIBOR alternate interest rate			1.50%
Commitment fee percentage	0.50%		0.50%
Maximum
Debt Instrument [Line Items]
Interest rate margin			3.50%
Revolving credit facility interest rate percent above LIBOR alternate interest rate			2.50%
Amended Credit Facility
Debt Instrument [Line Items]
Debt instrument, maturity date			Sep. 14, 2023
Line of credit facility, maximum borrowing capacity	$ 300,000,000.0		$ 300,000,000.0		$ 500,000,000.0
Principal amount	175,000,000		175,000,000			$ 140,000,000
Letters of credit issued amount	21,700,000		21,700,000
Line of credit facility, remaining borrowing capacity	53,300,000		53,300,000
Permitted Debt Resulting in Accelerated Maturity Date	100,000,000.0		100,000,000.0
Line of Credit Facility, Required Availability under the Credit Facility	50,000,000.0		50,000,000.0
Line of Credit Facility, Maximum Weekly Cash Balance	$ 35,000,000.0		$ 35,000,000.0

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Asset Retirement Obligations - Schedule of Asset Retirement Obligations (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2020 USD ($)
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
As of December 31, 2019	$ 25,709
Liabilities incurred	488
Liabilities settled	(766)
Disposition of properties	(143)
Accretion expense	872
Revisions to estimate	409
As of June 30, 2020	26,569
Less: Current asset retirement obligations	2,619
Long-term asset retirement obligations	$ 23,950

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Fair Value Measurements - Fair Value, Balance Sheet Grouping (Detail) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Financial Assets
Commodity derivatives	$ 87,782	$ 3,916
Financial Liabilities
Commodity derivatives	0	5,082
Total
Financial Assets
Deferred compensation plan	1,167	2,033
Commodity derivatives	91,150	8,890
Financial Liabilities
Commodity derivatives	3,368	10,056
Level 1
Financial Assets
Deferred compensation plan	1,167	2,033
Commodity derivatives	0	0
Financial Liabilities
Commodity derivatives	0	0
Level 2
Financial Assets
Deferred compensation plan	0	0
Commodity derivatives	91,150	8,890
Financial Liabilities
Commodity derivatives	3,368	10,056
Level 3
Financial Assets
Deferred compensation plan	0	0
Commodity derivatives	0	0
Financial Liabilities
Commodity derivatives	$ 0	$ 0

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Fair Value Measures - Level 3 Unobservable Inputs (Details)	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value, Unobservable Input, Level 3, Oil Price Range	$29 to $60
Fair Value, Unobservable Input, Level 3, Gas Price Range	$2.03 to $2.52
Fair Value, Unobservable Input, Level 3, NGL Price Range, % of Oil Price	24% to 31%
Fair Value, Unobservable Input, Level 3, % of PDP Reserves Adjusted	1
Fair Value, Unobservable Input, Level 3, % of PDN Reserves Adjusted	0.95
Fair Value, Unobservable Input, Level 3, Discount Rate	0.11

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Fair Value Measurements - Nonrecurring (Details) - USD ($) $ in Thousands	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Fair Value Measurements [Line Items]
Proved Oil and Gas Properties, Carrying Value, Before Impairment		$ 1,700,000
Unproved Oil and Gas Properties, Net Book Value Prior to Impairment		256,000
Proved Oil and Gas Properties
Fair Value Measurements [Line Items]
Impairment of Oil and Gas Properties	$ 0	1,200,000	$ 0	$ 1,188,566	$ 0
Proved Oil and Gas Properties | Level 3
Fair Value Measurements [Line Items]
Oil and Gas Property, Successful Effort Method, Net		500,000
Unproved Oil and Gas Properties
Fair Value Measurements [Line Items]
Impairment of Oil and Gas Properties	$ 0	76,300	$ 0	$ 76,298	$ 0
Unproved Oil and Gas Properties | Level 3
Fair Value Measurements [Line Items]
Oil and Gas Property, Successful Effort Method, Net		$ 179,700

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Fair Value Measurements - Additional Information (Detail) - USD ($)	3 Months Ended			6 Months Ended
	Jun. 30, 2020	Mar. 31, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Fair Value Measurements [Line Items]
Proved Oil and Gas Properties, Carrying Value, Before Impairment		$ 1,700,000,000
Principal amount	$ 800,000,000			$ 800,000,000		$ 765,000,000
7.0% Senior Notes
Fair Value Measurements [Line Items]
Debt, stated interest rate	7.00%			7.00%
Debt, fair value	$ 286,100,000			$ 286,100,000		335,000,000.0
Principal amount	$ 350,000,000			$ 350,000,000		350,000,000
8.75% Senior Notes
Fair Value Measurements [Line Items]
Debt, stated interest rate	8.75%			8.75%
Debt, fair value	$ 147,100,000			$ 147,100,000		251,200,000
Principal amount	275,000,000			275,000,000		275,000,000
Amended Credit Facility
Fair Value Measurements [Line Items]
Principal amount	175,000,000			175,000,000		$ 140,000,000
Proved Oil and Gas Properties
Fair Value Measurements [Line Items]
Impairment of Oil and Gas Properties	0	1,200,000,000	$ 0	1,188,566,000	$ 0
Unproved Oil and Gas Properties
Fair Value Measurements [Line Items]
Impairment of Oil and Gas Properties	$ 0	76,300,000	$ 0	$ 76,298,000	$ 0
Level 3 | Proved Oil and Gas Properties
Fair Value Measurements [Line Items]
Oil and Gas Property, Successful Effort Method, Net		500,000,000
Oil and Gas Property, Successful Effort Method, Net		500,000,000
Level 3 | Unproved Oil and Gas Properties
Fair Value Measurements [Line Items]
Oil and Gas Property, Successful Effort Method, Net		179,700,000
Oil and Gas Property, Successful Effort Method, Net		$ 179,700,000

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Derivative Instruments - Fair Value Amounts of Derivative Instruments (Detail) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	$ 91,150	$ 8,890
Gross Amounts Offset in the Balance Sheet (1)	(3,368)	(4,974)
Net Amounts of Assets Presented in the Balance Sheet	87,782	3,916
Gross Amounts of Recognized Liabilities	(3,368)	(10,056)
Gross Amounts Offset in the Balance Sheet (1)	3,368	4,974
Net Amounts of Liabilities Presented in the Balance Sheet	0	(5,082)
Derivative assets (current)
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	73,466	8,477
Gross Amounts Offset in the Balance Sheet (1)	(1,230)	(4,561)
Net Amounts of Assets Presented in the Balance Sheet	72,236	3,916
Derivative assets (noncurrent)
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Assets	17,684	413
Gross Amounts Offset in the Balance Sheet (1)	(2,138)	(413)
Net Amounts of Assets Presented in the Balance Sheet	15,546	0
Accounts payable and accrued liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(1,230)	(8,972)
Gross Amounts Offset in the Balance Sheet (1)	1,230	4,561
Net Amounts of Liabilities Presented in the Balance Sheet	0	(4,411)
Other noncurrent liabilities
Derivatives, Fair Value [Line Items]
Gross Amounts of Recognized Liabilities	(2,138)	(1,084)
Gross Amounts Offset in the Balance Sheet (1)	2,138	413
Net Amounts of Liabilities Presented in the Balance Sheet	$ 0	$ (671)

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Derivative Instruments - Financial Instruments for Hedging Volume (Detail)	Jun. 30, 2020 $ / unit bbl
Derivative, Swap Type | Oil (Bbls) | July – December 2020
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	2,760,000
Weighted Average Price (usd per unit) | $ / unit	56.59
Derivative, Swap Type | Oil (Bbls) | For the year 2021
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	3,098,000
Weighted Average Price (usd per unit) | $ / unit	54.30
Derivative, Swap Type | Oil (Bbls) | For the year 2022
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	0
Weighted Average Price (usd per unit) | $ / unit	0
Derivative, Swap Type | Natural Gas (MMbtu) | July – December 2020
Derivative Instruments, Gain (Loss) [Line Items]
Weighted Average Price (usd per unit) | $ / unit	1.83
Hedge Backed Gas Volume | bbl	3,680,000
Derivative, Swap Type | Natural Gas (MMbtu) | For the year 2021
Derivative Instruments, Gain (Loss) [Line Items]
Weighted Average Price (usd per unit) | $ / unit	2.13
Hedge Backed Gas Volume | bbl	5,790,000
Derivative, Swap Type | Natural Gas (MMbtu) | For the year 2022
Derivative Instruments, Gain (Loss) [Line Items]
Weighted Average Price (usd per unit) | $ / unit	0
Hedge Backed Gas Volume | bbl	0
Derivative, Roll Swaps | Oil (Bbls) | July – December 2020
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	276,500
Weighted Average Price (usd per unit) | $ / unit	(1.47)
Derivative, Roll Swaps | Oil (Bbls) | For the year 2021
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	0
Weighted Average Price (usd per unit) | $ / unit	0
Derivative, Roll Swaps | Oil (Bbls) | For the year 2022
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	0
Weighted Average Price (usd per unit) | $ / unit	0
Swaption | Oil (Bbls) | July – December 2020
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	0
Weighted Average Price (usd per unit) | $ / unit	0
Swaption | Oil (Bbls) | For the year 2021
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	0
Weighted Average Price (usd per unit) | $ / unit	0
Swaption | Oil (Bbls) | For the year 2022
Derivative Instruments, Gain (Loss) [Line Items]
Hedge backed oil volume | bbl	1,092,000
Weighted Average Price (usd per unit) | $ / unit	55.08

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Derivative Instruments - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2020 counterparty
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Number of counterparties for hedges at period end	8

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Income Taxes - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Income Tax Disclosure [Abstract]
(Provision for) Benefit from Income Taxes	$ 0	$ (110)	$ 95,280	$ 29,601
Deferred income taxes	2,137		2,137		$ 97,418
Income Taxes Receivable	$ 1,400		$ 1,400

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Additional Information (Detail)	6 Months Ended
	Jun. 30, 2020 $ / shares
Nonvested Equity Shares
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting period	3 years
Nonvested Equity Common Stock Units
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting period	1 year
Cash-Based Award
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting period	3 years
2020 Program [Member]
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Performance goal measurement period	3 years
Payout if absolute performance is 100%	100.00%
Relative TSR is less than 30%	30.00%
Payout if relative TSR is less than 30%	0.00%
Relative TSR is 30% or greater	30.00%
Payout if relative TSR is 30% or greater	100.00%
Closing Share Price, December 31, 2019	$ 1.69
2020 Program [Member] | Absolute Performance and Relative TSR | Maximum
Deferred Compensation Arrangement with Individual, Excluding Share-based Payments and Postretirement Benefits [Line Items]
Award vesting rights, percentage	200.00%

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Non-Cash Stock-Based Compensation Cost Related to Equity Awards (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019	Dec. 31, 2019
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	$ 1,550	$ 2,296	$ 2,006	$ 5,018
Unrecognized compensation expense	5,100		$ 5,100
Unrecognized compensation expense, recognition period			1 year 9 months 18 days
Nonvested Equity Shares
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	1,150	1,533	$ 2,300	3,329
Nonvested Equity Common Stock Units
Stock Based Compensation [Line Items]
Non-cash stock-based compensation equity awards	202	318	482	612
Nonvested Performance Cash Units
Stock Based Compensation [Line Items]
Nonvested performance cash units	198	$ 445	(776)	$ 1,077
Nonvested performance-based cash units accounted for as liability awards	$ 300		$ 300		$ 1,200

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Equity Incentive Compensation Plans and Other Long-term Incentive Programs - Stock Options and Nonvested Equity Shares, Equity Awards Granted (Detail) - $ / shares	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Nonvested Equity Shares
Units
Beginning balance (in shares)	3,531,812	3,431,780	2,968,497	2,912,166
Granted (in shares)	0	6,000	2,028,617	1,841,700
Vested (in shares)	(112,677)	(30,031)	(1,568,491)	(1,329,630)
Forfeited or expired (in shares)	(250,431)	(1,615)	(259,919)	(18,102)
Ending balance (in shares)	3,168,704	3,406,134	3,168,704	3,406,134
Weighted Average Grant Date Fair Value
Beginning balance (in dollars per share)	$ 2.10	$ 3.90	$ 3.81	$ 5.27
Granted (in dollars per share)	0	2.66	1.14	2.64
Vested (in dollars per share)	4.26	5.81	4.25	5.20
Forfeited or expired (in dollars per share)	1.52	7.14	1.59	4.96
Ending balance (in dollars per share)	$ 2.07	$ 3.88	$ 2.07	$ 3.88
Nonvested Performance Cash Units
Units
Beginning balance (in shares)	6,096,230	2,868,634	2,576,062	909,585
Granted (in shares)			3,569,434	2,026,521
Forfeited or expired (in shares)	(656,430)	0	(705,696)	(67,472)
Ending balance (in shares)	5,439,800	2,868,634	5,439,800	2,868,634
Weighted Average Grant Date Fair Value
Ending balance (in dollars per share)	$ 0.30	$ 1.82	$ 0.30	$ 1.82
Director
Units
Beginning balance (in shares)	796,103	311,237	796,103	311,237
Granted (in shares)	530,940	628,380	530,940	643,084
Vested (in shares)	(638,355)	(143,514)	(638,355)	(158,218)
Forfeited or expired (in shares)	(79,423)	0	(79,423)	0
Ending balance (in shares)	609,265	796,103	609,265	796,103
Weighted Average Grant Date Fair Value
Beginning balance (in dollars per share)	$ 3.27	$ 7.26	$ 3.27	$ 7.26
Granted (in dollars per share)	0.27	1.87	0.27	1.88
Vested (in dollars per share)	2.63	5.77	2.63	5.44
Forfeited or expired (in dollars per share)	0.25	0	0.25	0
Ending balance (in dollars per share)	$ 1.72	$ 3.27	$ 1.72	$ 3.27

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Leases Additional Details (Details)	Jun. 30, 2020
Leases [Abstract]
Term of contract	8 years

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Leases Lease Cost (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2020	Jun. 30, 2019	Jun. 30, 2020	Jun. 30, 2019
Leases [Abstract]
Operating lease cost	$ 529	$ 569	$ 1,039	$ 1,117
Short-term lease cost	789	4,167	3,052	10,386
Variable Lease, Cost	373	0	693	0
Total lease cost	$ 1,691	$ 4,736	$ 4,784	$ 11,503

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Leases Supplemental Balance Sheet (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019	Jan. 01, 2019
Leases [Abstract]
Right-of-use assets	$ 9,906	$ 9,287
Accumulated amortization	(1,621)	(1,142)
Total right-of-use assets, net	8,285	8,145	$ 14,000
Current lease liabilities	1,954	1,287
Noncurrent lease liabilities	12,834	13,195
Total lease liabilities	$ 14,788	$ 14,482
Weighted average remaining lease term
Operating leases (in years)	7 years 3 months 18 days	7 years 9 months 18 days
Weighted average discount rate
Operating leases	5.60%	5.60%

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Leases Maturity (Details) - USD ($) $ in Thousands	Jun. 30, 2020	Dec. 31, 2019
Leases [Abstract]
2020	$ 1,377	$ 2,056
2021	2,635	2,355
2022	2,324	2,044
2023	2,101	2,024
2024	2,078	2,078
Thereafter	7,576	7,577
Total	18,091	18,134
Less: Interest	(3,303)	(3,652)
Present value of lease liabilities	$ 14,788	$ 14,482

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Commitments and Contingencies - Additional Information (Detail) a in Thousands, $ in Millions	6 Months Ended
	Jun. 30, 2020 USD ($) a agreement integer
Commitments and Contingencies Disclosure [Abstract]
Number of firm transportation contracts | agreement	2
Number of firm pipeline transportation contracts	1
Minimum volume commitment	1
Number of reimbursement obligations	2
Number of other commitments	2
Number of Drilling Commitments	1
Number of Wells Due by July 2022	2
Number of Wells Due by July 2023	3
Acreage to be Assigned if Drilling Commitment Not Met | a	13
Drilling Commitment Due 2022 | $	$ 10.2
Drilling Commitment Due 2023 | $	$ 15.3

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Commitments and Contingencies - Gross Future Minimum Transportation Demand and Firm Processing Charges (Detail) $ in Thousands	Jun. 30, 2020 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2020	$ 12,732
2021	19,777
2022	13,064
2023	14,600
2024	14,640
Thereafter	4,800
Total	$ 79,613

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Commitments and Contingencies Commitments And Contingencies - Gross Future Minimum Volume Charges (Details) $ in Thousands	Jun. 30, 2020 USD ($)
Commitments and Contingencies - Gross Future Minimum Volume Charges [Abstract]
2020	$ 1,089
2021	5,268
Thereafter	0
Total	$ 6,357

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Commitments and Contingencies - Other Commitments (Detail) $ in Thousands	Jun. 30, 2020 USD ($)
Commitments and Contingencies Disclosure [Abstract]
2020	$ 1,098
2021	1,285
2022	11,485
2023	16,285
Thereafter	0
Total	$ 30,153