UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

(Mark One)



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

For the quarterly period ended ~~March 31, 2018~~September 30, 2020



o☐			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 ~~333-222275~~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



~~1099 18th Street, Suite 2300~~ ~~Denver, Colorado~~		Denver, Colorado 80202
~~(Address of principal executive offices)~~		~~(Zip Code)~~

(Address of principal executive offices, including zip code)

(303) 293-9100

(~~Registrant's~~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. x☑ Yes o☐ No

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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). x☑ Yes o☐ 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~~“large accelerated filer,~~" "accelerated~~” “accelerated filer,~~" "smaller~~” “smaller reporting company,"” and ~~"emerging~~“emerging growth ~~company"~~company” in Rule 12b-2 of the Exchange Act.

Large accelerated filer

o☐

Accelerated filer

x☑

Non-accelerated filer

o ~~(Do not check if a smaller reporting company)~~

☐

Smaller reporting company

o☐

Emerging growth company

o☐

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). o☐ Yes x☑ No

There were ~~212,008,080~~4,305,119 shares of $0.001 par value common stock outstanding on ~~April 24, 2018~~.October 30, 2020.

Table of Contents

INDEX TO FINANCIAL STATEMENTS




PART I. FINANCIAL INFORMATION

Item 1.	Consolidated Financial Statements (Unaudited)	3
Item 2.	~~Management's~~Management ’s Discussion and Analysis of Financial Condition and Results of Operations	31	27
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	41	46
Item 4.	Controls and Procedures	41	47

PART II. OTHER INFORMATION

Item 1.	Legal Proceedings	42	48
Item 1A.	Risk Factors	42	48
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	42	50
Item 3.	Defaults Upon Senior Securities	42	50
Item 4.	Mine Safety Disclosures	42	50
Item 5.	Other Information	42	50
Item 6.	Exhibits	42	51
SIGNATURES		44	52

Table of Contents

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)


	September 30, 2020		December 31, 2019
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	26,894	$	16,449
Accounts receivable, net of allowance	44,076		62,120

Derivative assets	46,989		3,916

Prepayments and other current assets	5,566		3,952
Total current assets	123,525		86,437
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,758,484		2,644,129
Unproved oil and gas properties, excluded from amortization	231,883		357,793
Furniture, equipment and other	30,450		29,804
	3,020,817		3,031,726
Accumulated depreciation, depletion, amortization and impairment	(2,259,675)		(967,552)
Total property and equipment, net	761,142		2,064,174

Derivative assets	4,591		0
Other noncurrent assets	12,955		5,441
Total	$	902,213	$	2,156,052
Liabilities and Stockholders’ Equity (Deficit):
Current Liabilities:
Accounts payable and accrued liabilities	$	47,245	$	71,638
Amounts payable to oil and gas property owners	33,174		37,922
Production taxes payable	22,239		61,507
Derivative liabilities	0		4,411



Total current liabilities	102,658		175,478
Long-term debt, net of debt issuance costs	760,054		758,911
Asset retirement obligations	24,413		23,491
Deferred income taxes	1,556		97,418
Other noncurrent liabilities	26,147		17,436
Commitments and contingencies (Note 11)
Stockholders’ Equity (Deficit):
Common stock, $0.001 par value; authorized 8,000,000 shares; 4,305,252 and 4,273,391 shares issued and outstanding at September 30, 2020 and December 31, 2019, respectively, with 58,956 and 59,369 shares subject to restrictions, respectively (1)	4		4
Additional paid-in capital (1)	1,781,125		1,777,986
Accumulated deficit	(1,793,744)		(694,672)
Treasury stock, at cost: zero shares at September 30, 2020 and December 31, 2019 (1)	0		0
Total stockholders’ equity (deficit)	(12,615)		1,083,318
Total	$	902,213	$	2,156,052

March 31, 2018 December 31, 2017
(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents $ 224,692
$ 314,466
Accounts receivable, net of allowance for doubtful accounts 50,268
51,415
Prepayments and other current assets 2,393
1,782
Total current assets 277,353
367,663
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties 1,568,921
1,361,168
Unproved oil and gas properties, excluded from amortization 708,917
84,676
Furniture, equipment and other 18,921
17,899
2,296,759
1,463,743
Accumulated depreciation, depletion, amortization and impairment (485,317 ) (444,863 )
Total property and equipment, net 1,811,442
1,018,880
Deferred financing costs and other noncurrent assets 3,679
4,163
Total $ 2,092,474
$ 1,390,706
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and other accrued liabilities $ 135,925
$ 84,055
Amounts payable to oil and gas property owners 30,852
16,594
Production taxes payable 35,533
26,876
Derivative liabilities 35,866
20,940
Current portion of long-term debt 2,212
469
Total current liabilities 240,388
148,934
Long-term debt, net of debt issuance costs 616,244
617,744
Asset retirement obligations 23,907
16,097
Deferred income taxes 137,111
—
Derivatives and other noncurrent liabilities 14,484
9,377
Commitments and contingencies (Note 13)

Stockholders' equity:
Common stock, $0.001 par value; authorized 400,000,000 and 300,000,000 shares at March 31, 2018 and December 31, 2017, respectively; 212,008,260 and 110,363,539 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively, with 2,657,535 and 1,394,868 shares subject to restrictions, respectively 209
109
Additional paid-in capital 1,766,130
1,279,507
Retained earnings (accumulated deficit) (705,999 ) (681,062 )
Treasury stock, at cost: zero shares at March 31, 2018 and December 31, 2017 —
—
Total stockholders' equity 1,060,340
598,554
Total $ 2,092,474
$ 1,390,706

(1)Amounts and shares have been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

See notes to Unaudited Consolidated Financial Statements.

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production	$	67,305	$	121,281	$	190,171	$	330,472
Other operating revenues, net	42		1		42		374
Total operating revenues	67,347		121,282		190,213		330,846
Operating Expenses:
Lease operating expense	5,305		8,385		25,460		30,434
Gathering, transportation and processing expense	5,317		1,611		13,983		5,076
Production tax expense	(1,074)		7,868		(2,133)		20,666
Exploration expense	74		56		126		93
Impairment and abandonment expense	2,813		1,170		1,269,049		2,487
(Gain) loss on sale of properties	18		0		4,797		2,901
Depreciation, depletion and amortization	25,522		84,948		125,355		230,170
Unused commitments	4,985		4,418		13,821		13,239
General and administrative expense	12,891		11,048		35,996		36,109
Merger transaction expense	0		2,078		0		4,492
Other operating expenses, net	(38)		230		(540)		210
Total operating expenses	55,813		121,812		1,485,914		345,877
Operating Income (Loss)	11,534		(530)		(1,295,701)		(15,031)
Other Income and Expense:
Interest and other income (expense)	171		94		235		562
Interest expense	(14,346)		(15,167)		(44,117)		(43,227)
Commodity derivative gain (loss)	(13,746)		31,047		144,649		(54,600)

Total other income and expense	(27,921)		15,974		100,767		(97,265)
Income (Loss) before Income Taxes	(16,387)		15,444		(1,194,934)		(112,296)
(Provision for) Benefit from Income Taxes	582		(4,330)		95,862		25,271
Net Income (Loss)	$	(15,805)	$	11,114	$	(1,099,072)	$	(87,025)
Net Income (Loss) Per Common Share, Basic (1)	$	(3.72)	$	2.64	$	(259.52)	$	(20.69)
Net Income (Loss) Per Common Share, Diluted (1)	$	(3.72)	$	2.63	$	(259.52)	$	(20.69)
Weighted Average Common Shares Outstanding, Basic (1)	4,246,047		4,210,993		4,235,432		4,205,768
Weighted Average Common Shares Outstanding, Diluted (1)	4,246,047		4,218,745		4,235,432		4,205,768

Three Months Ended March 31,
2018 2017
(in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production $ 80,831
$ 50,425
Other operating revenues, net (21 ) 111
Total operating revenues 80,810
50,536
Operating Expenses:
Lease operating expense 6,251
5,862
Gathering, transportation and processing expense 419
489
Production tax expense 5,175
322
Exploration expense 13
27
Impairment, dry hole costs and abandonment expense 317
8,074
(Gain) loss on sale of properties 408
(92 )
Depreciation, depletion and amortization 40,985
38,340
Unused commitments 4,538
4,572
General and administrative expense 10,107
9,349
Merger transaction expense 4,763
—
Other operating expenses, net 39
(573 )
Total operating expenses 73,015
66,370
Operating Income (Loss) 7,795
(15,834 )
Other Income and Expense:
Interest and other income 691
206
Interest expense (13,090 ) (13,951 )
Commodity derivative gain (loss) (20,333 ) 16,464
Total other income and expense (32,732 ) 2,719
Income (Loss) before Income Taxes (24,937 ) (13,115 )
(Provision for) Benefit from Income Taxes —
—
Net Income (Loss) $ (24,937 ) $ (13,115 )
Net Income (Loss) Per Common Share, Basic $ (0.20 ) $ (0.18 )
Net Income (Loss) Per Common Share, Diluted $ (0.20 ) $ (0.18 )
Weighted Average Common Shares Outstanding, Basic 123,595,553
74,543,780
Weighted Average Common Shares Outstanding, Diluted 123,595,553
74,543,780

(1)All share and per share information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

See notes to Unaudited Consolidated Financial Statements.

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF ~~COMPREHENSIVE INCOME (LOSS)~~CASH FLOWS

(UNAUDITED)


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(1,099,072)	$	(87,025)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	125,355		230,170
Deferred income taxes	(95,862)		(25,271)
Impairment and abandonment expense	1,269,049		2,487
Commodity derivative (gain) loss	(144,649)		54,600
Settlements of commodity derivatives	92,506		7,731
Stock compensation and other non-cash charges	3,947		9,501
Amortization of deferred financing costs	2,854		1,917

(Gain) loss on sale of properties	4,797		2,901
Change in operating assets and liabilities:
Accounts receivable	8,012		13,488
Prepayments and other assets	(1,609)		(1,109)
Accounts payable, accrued and other liabilities	(5,840)		3,867
Amounts payable to oil and gas property owners	(4,748)		(16,784)
Production taxes payable	(28,012)		(1,079)

Net cash provided by (used in) operating activities	126,728		195,394
Investing Activities:
Additions to oil and gas properties, including acquisitions	(118,281)		(375,976)
Additions of furniture, equipment and other	(855)		(3,958)




Other investing activities	3,602		(66)
Net cash provided by (used in) investing activities	(115,534)		(380,000)
Financing Activities:
Proceeds from debt	120,000		200,000
Principal payments on debt	(120,000)		(26,859)



Other financing activities	(749)		(1,741)
Net cash provided by (used in) financing activities	(749)		171,400
Increase (Decrease) in Cash and Cash Equivalents	10,445		(13,206)
Beginning Cash and Cash Equivalents	16,449		32,774
Ending Cash and Cash Equivalents	$	26,894	$	19,568

Three Months Ended March 31,
2018 2017
(in thousands)
Net Income (Loss) $ (24,937 ) $ (13,115 )
Other comprehensive income (loss) —
—
Comprehensive Income (Loss) $ (24,937 ) $ (13,115 )

See notes to Unaudited Consolidated Financial Statements.

Table of Contents

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF ~~CASH FLOWS~~STOCKHOLDERS’ EQUITY (DEFICIT)

(UNAUDITED)

(In thousands)

Three Months Ended March 31,
2018 2017
(in thousands)
Operating Activities:
Net Income (Loss) $ (24,937 ) $ (13,115 )
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization 40,985
38,340
Impairment, dry hole costs and abandonment expense 317
8,074
Commodity derivative (gain) loss 20,333
(16,464 )
Settlements of commodity derivatives (8,388 ) 3,632
Stock compensation and other non-cash charges 835
1,968
Amortization of deferred financing costs 563
558
(Gain) loss on sale of properties 408
(92 )
Change in operating assets and liabilities:
Accounts receivable 9,166
3,587
Prepayments and other assets (111 ) (1,047 )
Accounts payable, accrued and other liabilities 822
8,965
Amounts payable to oil and gas property owners 9,609
1,090
Production taxes payable 4,715
2,602
Net cash provided by (used in) operating activities 54,317
38,098
Investing Activities:
Additions to oil and gas properties, including acquisitions (88,854 ) (57,963 )
Additions of furniture, equipment and other (122 ) (11 )
Repayment of debt associated with merger, net of cash acquired (53,357 ) —
Proceeds from sale of properties and other investing activities (157 ) 11,225
Net cash provided by (used in) investing activities (142,490 ) (46,749 )
Financing Activities:
Principal payments on debt (116 ) (112 )
Proceeds from sale of common stock, net of offering costs —
(224 )
Deferred financing costs and other (1,485 ) (967 )
Net cash provided by (used in) financing activities (1,601 ) (1,303 )
Increase (Decrease) in Cash and Cash Equivalents (89,774 ) (9,954 )
Beginning Cash and Cash Equivalents 314,466
275,841
Ending Cash and Cash Equivalents $ 224,692
$ 265,887


	Three Months Ended September 30, 2020 and 2019
	Common Stock (1)		Additional Paid-In Capital (1)		Accumulated Deficit		Treasury Stock		Total Stockholders’ Equity (Deficit)
Balance at June 30, 2020	$	4	$	1,780,114	$	(1,777,939)	$	0	$	2,179

Restricted stock activity and shares exchanged for tax withholding	—		—		—		(14)		(14)
Stock-based compensation	—		1,025		—		—		1,025
Retirement of treasury stock	—		(14)		—		14		0




Net income (loss)	—		—		(15,805)		—		(15,805)
Balance at September 30, 2020	$	4	$	1,781,125	$	(1,793,744)	$	0	$	(12,615)

Balance at June 30, 2019	$	4	$	1,774,370	$	(657,981)	$	0	$	1,116,393

Restricted stock activity and shares exchanged for tax withholding	—		1		—		(219)		(218)
Stock-based compensation	—		2,274		—		—		2,274
Retirement of treasury stock	—		(219)		—		219		0




Net income (loss)	—		—		11,114		—		11,114
Balance at September 30, 2019	$	4	$	1,776,426	$	(646,867)	$	0	$	1,129,563

	Nine Months Ended September 30, 2020 and 2019
	Common Stock (1)		Additional Paid-In Capital (1)		Accumulated Deficit		Treasury Stock		Total Stockholders’ Equity (Deficit)
Balance at December 31, 2019	$	4	$	1,777,986	$	(694,672)	$	0	$	1,083,318

Restricted stock activity and shares exchanged for tax withholding	—		1		—		(668)		(667)
Stock-based compensation	—		3,806		—		—		3,806
Retirement of treasury stock	—		(668)		—		668		0




Net income (loss)	—		—		(1,099,072)		—		(1,099,072)
Balance at September 30, 2020	$	4	$	1,781,125	$	(1,793,744)	$	0	$	(12,615)

Balance at December 31, 2018	$	4	$	1,771,936	$	(559,842)	$	0	$	1,212,098

Restricted stock activity and shares exchanged for tax withholding	—		1		—		(1,725)		(1,724)
Stock-based compensation	—		6,214		—		—		6,214
Retirement of treasury stock	—		(1,725)		—		1,725		0




Net income (loss)	—		—		(87,025)		—		(87,025)
Balance at September 30, 2019	$	4	$	1,776,426	$	(646,867)	$	0	$	1,129,563

(1)Amounts have been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

See notes to Unaudited Consolidated Financial Statements.

Table of Contents

HIGHPOINT RESOURCES CORPORATION

~~CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY~~

~~(UNAUDITED)~~

~~(In thousands)~~

Common
Stock

Additional
Paid-In
Capital

Retained
Earnings (Accumulated Deficit)

Treasury
Stock
Total
Stockholders'
Equity
Balance at December 31, 2016 $ 74
$ 1,113,797
$ (542,328 ) $ —
$ 571,543
Cumulative effect of accounting change —
180
(509 ) —
(329 )
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding 1
—
—
(1,253 ) (1,252 )
Stock-based compensation —
7,099
—
—
7,099
Retirement of treasury stock —
(1,253 ) —
1,253
—
Exchange of senior notes for shares of common stock 11
48,981
—
—
48,992
Issuance of common stock, net of offering costs 23
110,703
—
—
110,726
Net income (loss) —
—
(138,225 ) —
(138,225 )
Balance at December 31, 2017 109
1,279,507
(681,062 ) —
598,554
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding —
—
—
(1,462 ) (1,462 )
Stock-based compensation ⁽¹⁾
—
4,185
—
—
4,185
Retirement of treasury stock —
(1,462 ) —
1,462
—
Issuance of common stock, merger 100
483,900
—
—
484,000
Net income (loss) —
—
(24,937 ) —
(24,937 )
Balance at March 31, 2018 $ 209
$ 1,766,130
$ (705,999 ) $ —
$ 1,060,340

~~See notes to Unaudited Consolidated Financial Statements.~~


~~(1)~~	~~As of March 31, 2018, includes the modification of the 2016 Program and 2017 Program from performance-based liability awards to service-based equity awards. See Note 11 for additional information.~~

~~HIGHPOINT RESOURCES CORPORATION~~

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

~~March 31, 2018~~September 30, 2020

1. Organization

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the ~~"Company"~~“Company” or “HighPoint”), is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids ~~("NGLs"~~(“NGLs”). The Company became the successor to Bill Barrett Corporation ("(“Bill ~~Barrett"~~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"~~“2018 Merger Agreement”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC ("(“Fifth ~~Creek"~~Creek”) (the ~~"Merger"~~“2018 Merger”). As a result of the 2018 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"~~Basin”) in Colorado. Except where the context indicates otherwise, references herein to the ~~"Company"~~“Company” with respect to periods prior to the completion of the 2018 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"~~(“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~~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 ~~filed by the Company's predecessor Bill Barrett~~ for the year ended December 31, ~~2017~~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 ~~Bill Barrett 2017~~ Annual Report on ~~Form10-K.~~Form 10-K.

On October 20, 2020, the Company announced a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-50 and a proportionate reduction of the total number of authorized shares of common stock, which was approved by the stockholders at the Company’s Annual Meeting of Stockholders on April 28, 2020. The reverse stock split became effective on October 30, 2020, and the Company’s common stock was traded on a split-adjusted basis on the New York Stock Exchange (“NYSE”) at the market open on that date. The par value of the common stock was not adjusted as a result of the reverse stock split. All share and per share amounts were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of the Company’s common stock to additional paid-in capital. See Note 12 for additional information.

Going Concern. The accompanying consolidated financial statements are prepared in accordance with GAAP applicable to a going concern, which contemplates the realization of assets and the satisfaction of liabilities in the normal course of business. In accordance with the accounting guidance related to the presentation of financial statements, when preparing financial statements for each annual and interim reporting period, management evaluates whether there are conditions or events that, when considered in the aggregate, raise substantial doubt about the Company’s ability to continue as a going concern within one year after the date that the financial statements are issued. In making its assessment, management considered the Company’s current financial condition and liquidity sources, including current funds available, forecasted future cash flows and conditional and unconditional obligations due over the next twelve months.

The ~~Unaudited Consolidated Statement~~Company has been impacted by the decreased demand for oil, natural gas and NGLs caused by the COVID-19 pandemic, along with other recent macro and microeconomic factors, which resulted in a significant decrease in market prices for oil, natural gas and NGLs beginning in March 2020. These events negatively impacted the Company’s ability to continue its development plan, which results in a decrease in future production, and led to a reduction in the Company’s borrowing base and elected commitment amounts under its revolving credit facility (“Credit Facility”).

The Company’s Credit Facility is subject to financial covenants. As of ~~Operations~~September 30, 2020, the Company is in compliance with all financial covenants under the Credit Facility. However, based on the Company’s forecasted cash flow analysis for the

Table of Contents

twelve month period subsequent to the date of this filing, which reflects its expectations of future market pricing, current open commodity hedge contracts, anticipated production volumes and estimates of operating, investing and financial cash flows, it is probable the Company will breach a financial covenant under the Company’s Credit Facility in the second quarter of 2021. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of September 30, 2020. This would, in turn, result in cross-default under the indentures to the Company’s senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of September 30, 2020. Further, if the Company’s independent auditor includes an explanatory paragraph regarding the Company’s ability to continue as a “going concern” in its report on the Company’s financial statements for the ~~three months ended March~~year ending December 31, ~~2018 reflects seventy-eight days~~2020, this would accelerate a default under the Company’s Credit Facility to the first quarter of ~~Bill Barrett operations~~2021 at the time the Company’s financial statements for the year ending December 31, 2020 are filed and, ~~twelve days~~in turn, result in cross-default under the indentures to the senior notes at that time as well. The Company does not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about the Company’s ability to continue as a going concern.

In response to these conditions, the Company has taken various steps to preserve its liquidity including (1) deferring drilling and completion activity starting in May 2020 for the foreseeable future, (2) continuing to focus on reducing its operating and overhead costs, and (3) continuing to manage its hedge portfolio. The Company could remain in compliance with the financial covenant if it (1) negotiates a waiver of the ~~merged entities' operations.~~covenant with the lenders, (2) negotiates more flexible financial covenants, or (3) refinances the Credit Facility or senior notes. However, the availability of capital funding that would allow the Company to refinance the debt on terms acceptable to the Company has substantially diminished. In addition, the Company has engaged advisors to assist with the evaluation of a range of strategic alternatives and is engaged in discussions with its lenders and bondholders regarding a potential comprehensive restructuring of the Company’s indebtedness. However, these plans have not been finalized, are subject to market conditions, are not within the Company’s control, and therefore cannot be deemed probable of being implemented. As a result, the Company has concluded that management’s plans do not alleviate substantial doubt about the Company’s ability to continue as a going concern.

The consolidated financial statements do not include any adjustments relating to the recoverability and classification of recorded asset amounts or the amounts and classification of liabilities that might result from the outcome of this uncertainty.

Use of Estimates. In the course of preparing the ~~Company's~~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"~~&A”), the amount of expected future cash flows used in determining ~~possible~~ 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 ~~valuing deferred tax assets~~ and ~~estimating~~ 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 September 30, 2020		As of December 31, 2019
	(in thousands)
Oil, gas and NGL sales	$	31,743	$	50,171
Due from joint interest owners (1)	10,596		9,551
Other	2,459		2,419
Allowance for doubtful accounts	(722)		(21)
Total accounts receivable	$	44,076	$	62,120

(1)Includes $6.3 million of current accounts receivable associated with one joint interest partner. An additional $10.0 million due from this joint interest partner has been reclassed to long term and included in other noncurrent assets on the Unaudited

Table of Contents

As of March 31, 2018 As of December 31, 2017
(in thousands)
Oil, gas and NGL sales $ 41,056
$ 36,569
Due from joint interest owners 9,081
14,779
Other 132
270
Allowance for doubtful accounts (1 ) (203 )
Total accounts receivable $ 50,268
$ 51,415
Consolidated Balance Sheet. The Company will net the outstanding amounts against certain revenues payable to this joint interest partner.

Oil and Gas Properties. The Company's oil, gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized and are included within additions to oil and gas properties and remain within cash flows from investing activities in the Unaudited Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added or not. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized.

Other exploration costs, including certain geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. The sale of a partial interest in a proved property is accounted for as a cost recovery and no gain or loss is recognized as long as this treatment does not significantly affect the unit-of-production amortization rate. Maintenance and repairs are charged to expense, and renewals and betterments are capitalized to the appropriate property and equipment accounts.

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. 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.

~~Materials and supplies consist primarily of tubular goods and well equipment to be used in future drilling operations or repair operations and are carried at the lower of cost or market value.~~

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


	As of September 30, 2020		As of December 31, 2019
	(in thousands)
Proved properties	$	720,735	$	725,964
Wells and related equipment and facilities	1,919,297		1,805,136
Support equipment and facilities	105,965		99,540
Materials and supplies	12,487		13,489
Total proved oil and gas properties	$	2,758,484	$	2,644,129
Unproved properties	179,492		265,387
Wells and facilities in progress	52,391		92,406
Total unproved oil and gas properties, excluded from amortization	$	231,883	$	357,793
Accumulated depreciation, depletion, amortization and impairment	(2,248,522)		(958,475)
Total oil and gas properties, net	$	741,845	$	2,043,447

As of March 31, 2018 As of December 31, 2017
(in thousands)
Proved properties $ 340,584
$ 230,800
Wells and related equipment and facilities 1,173,470
1,088,692
Support equipment and facilities 49,233
38,776
Materials and supplies 5,634
2,900
Total proved oil and gas properties ⁽¹⁾
$ 1,568,921
$ 1,361,168
Unproved properties ⁽¹⁾
626,487
18,832
Wells and facilities in progress 82,430
65,844
Total unproved oil and gas properties, excluded from amortization $ 708,917
$ 84,676
Accumulated depreciation, depletion, amortization and impairment (473,428 ) (433,234 )
Total oil and gas properties, net $ 1,804,410
$ 1,012,610


~~(1)~~	~~Includes properties acquired in the Merger of $105.7 million of proved oil and gas properties and $607.5 million of unproved properties. See Note 4 for additional information regarding the Merger.~~

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 ~~Company's~~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 based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net cash flows of its oil and gas~~

~~properties represent the applicable market~~ 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.

~~In addition,~~Unproved oil and gas properties are assessed periodically for impairment ~~once they meet~~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 ~~criteria~~spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to ~~be classified~~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 ~~held~~“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 ~~sale. Assets held~~the month of March 2020, compared to an average of $59.80 per barrel for ~~sale are carried at~~ the ~~lower~~month of ~~carrying cost or fair value less costs~~December 2019. These events led to ~~sell. The fair~~a decline in the recoverability of the carrying value of the ~~assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available,~~Company’s oil and gas properties during the ~~Company utilizes the income valuation technique, which involves calculating the present value of future net cash flows as discussed above. If~~three months ended March 31, 2020. Since the carrying amount of the ~~assets exceeds~~oil and gas properties was no longer recoverable, the ~~fair~~Company impaired the carrying value ~~less costs to sell, an impairment will result to reduce the value of the properties down~~ to fair ~~value less costs to sell.~~

~~The~~value. Therefore, the Company recognized non-cash impairment charges during the three months ended March 31, 2020 of $1.3 billion, which were included within impairment ~~dry hole costs~~ and abandonment expense in the Unaudited Consolidated Statements of ~~Operations, as follows:~~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.

Table of Contents

Three Months Ended March 31,
2018 2017
(in thousands)
Impairment of unproved oil and gas properties ⁽¹⁾
$ —

$ 8,010
Dry hole costs —
2
Abandonment expense and lease expirations 317
62
Total impairment, dry hole costs and abandonment expense $ 317
$ 8,074


~~(1)~~	The Company recognized impairment related to unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin during the three months ended March 31, 2017. The Company had no current plan to develop this acreage.

The ~~provision~~Company’s impairment and abandonment expense for ~~DD&A~~the three and nine months ended September 30, 2020 and 2019 is summarized below:


	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Impairment of proved oil and gas properties (1)	$	0	$	0	$	1,188,566	$	0
Impairment of unproved oil and gas properties (1)(2)	2,537		0		78,835		0


Abandonment expense	276		1,170		1,648		2,487
Total impairment and abandonment expense	$	2,813	$	1,170	$	1,269,049	$	2,487

(1)Due to a decline in the recoverability of the carrying value of the Company’s oil and gas properties ~~is calculated on~~during the nine months ended September 30, 2020, the Company recognized non-cash impairment charges of $1.2 billion associated with proved oil and gas properties and $76.3 million associated with unproved oil and gas properties.

(2)As a ~~field-by-field basis using~~result of the ~~unit-of-production method. Natural~~Company’s continuous review of its acreage position and future drilling plans, the Company recognized $2.5 million of non-cash impairment associated with unproved oil and gas ~~and NGLs are converted~~properties during the three months ended September 30, 2020 associated with certain leases that will expire subsequent to ~~an oil equivalent, Boe, at~~ the ~~standard rate of six Mcf~~balance sheet date that the Company does not plan to ~~one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.~~renew.

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


	As of September 30, 2020		As of December 31, 2019
	(in thousands)
Accrued drilling, completion and facility costs	$	6,700	$	25,667
Accrued lease operating, gathering, transportation and processing expenses	6,113		8,046
Accrued general and administrative expenses	7,985		6,612
Accrued interest payable	18,739		6,832



Trade payables	3,366		17,488
Operating lease liability	1,955		1,287
Other	2,387		5,706
Total accounts payable and accrued liabilities	$	47,245	$	71,638

As of March 31, 2018 As of December 31, 2017
(in thousands)
Accrued drilling, completion and facility costs $ 72,049
$ 35,856
Accrued lease operating, gathering, transportation and processing expenses 7,557
4,360
Accrued general and administrative expenses 8,779
11,134
Accrued interest payable 18,615
6,484
Accrued merger transaction expenses 6,169
8,278
Accrued hedge settlements 3,408
65
Prepayments from partners 1,461
2,524
Trade payables 13,069
10,067
Other 4,818
5,287
Total accounts payable and other accrued liabilities $ 135,925
$ 84,055

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. ~~Recent case~~Under Wyoming law, ~~in Wyoming has~~the Company is exposed us to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were

sold to other industry parties in prior ~~years that~~years. When such third parties are ~~now~~unable to fulfill their contractual obligations to the Company as provided for in ~~default. Regulatory agencies~~purchase and sale agreements, landowners, ~~have demanded~~as well as the Bureau of Land Management, may demand that the Company perform such activities. As of September 30, 2020, the Company has completed the plugging and abandonment operations identified through such demands.

Revenue Recognition. All of the ~~Company's~~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~~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~~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~~Company’s contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of ~~March 31, 2018,~~September 30, 2020, the Company had open contracts with customers with terms of 1 month to 2018 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The ~~Company's~~Company’s contracts with customers typically require payment within one month of delivery.

Under the ~~Company's~~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

Table of Contents

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~~Company’s oil is sold to anmultiple oil ~~purchaser~~purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the ~~Company's~~Company’s oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and ~~thus~~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~~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)~~under produced) imbalance. Imbalances ~~have~~were not ~~been~~ 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. ~~Deferred~~A valuation allowance is recorded if it is more likely than not that all or some portion of the Company’s deferred tax assets ~~are~~will not be realized. The Company regularly ~~reviewed,~~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, ~~taxable~~planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine ~~whether it~~if a valuation allowance is ~~more likely than not that~~required. Changes to the ~~deferred~~Company’s development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors including changes in tax ~~asset will be realized.~~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 ~~March 31, 2018.~~September 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 ~~equity~~shares of common stock. The diluted net income per common share excludes the anti-dilutive effect of 62,142 nonvested shares of common stock, ~~and in-the-money outstanding~~retroactively adjusted to reflect a 1-for-50 reverse stock ~~options to purchase~~split, for the ~~Company's common stock. As the~~three months ended September 30, 2019. The Company was in a net loss position for the three and nine months ended September 30, 2020 and the nine months ended September 30, 2019; therefore, all potentially dilutive securities were ~~anti-dilutive for the three months ended March 31, 2018 and 2017.~~anti-dilutive.

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

Table of Contents


	Three Months Ended March 31,								Three Months Ended September 30,								Nine Months Ended September 30,
	2018			2017					2020				2019				2020				2019
	(in thousands, except per share amounts)								(in thousands, except per share amounts)
Net income (loss)	$	(24,937	)	$	(13,115	)	Net income (loss)		$	(15,805)			$	11,114			$	(1,099,072)			$	(87,025)
Basic weighted-average common shares outstanding in period	123,596			74,544
Basic weighted-average common shares outstanding in period (1)							Basic weighted-average common shares outstanding in period (1)		4,246				4,211				4,235				4,206
Add dilutive effects of stock options and nonvested equity shares of common stock (1)							Add dilutive effects of stock options and nonvested equity shares of common stock (1)		0				8				0				0
Diluted weighted-average common shares outstanding in period(1)	123,596			74,544			4,246				4,219				4,235				4,206
Basic net income (loss) per common share(1)	$	(0.20	)	$	(0.18	)	$	(3.72)			$	2.64			$	(259.52)			$	(20.69)
Diluted net income (loss) per common share(1)	$	(0.20	)	$	(0.18	)	$	(3.72)			$	2.63			$	(259.52)			$	(20.69)

(1)All share and per share information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

New Accounting Pronouncements. In ~~May 2017,~~April 2020, the Financial Accounting Standards Board ~~("FASB"~~(“FASB”) issued Accounting Standards Update ~~("ASU"~~(“ASU”) ~~2017-09,~~ ~~Stock Compensation-Scope~~2020-04, Facilitation of ~~Modification Accounting~~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 ~~provide clarity and reduce both diversity in practice and cost and complexity when applying a change to~~improve the ~~terms or conditions~~effectiveness of ~~a share-based payment award.~~fair value measurement disclosures. ASU ~~2017-09~~2018-13 is effective for annual periods beginning after December 15, ~~2017,~~2019 and interim periods within those annual periods. The standard was adopted ~~for this interim period ended March 31, 2018~~on January 1, 2020 and did not have a material impact on the ~~Company's disclosures and financial statements.~~Company’s disclosures.

In ~~January 2017,~~June 2016, the FASB issued ASU ~~2017-01,~~ ~~Business Combinations: Clarifying the definition of a business~~2016-13, Financial Instruments, Credit Losses. The objective of this update is to ~~clarify~~amend current impairment guidance by adding an impairment model (known as the ~~definition~~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 a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions (or disposals) of assets or businesses. ASU 2017-01 is effective for annual and interim periods beginning after December 15, 2017. The standard was adopted prospectively for this interim period ended March 31, 2018 and did not have a material impact on the Company's disclosures and financial statements. The accounting treatment of the Merger was not affected by this guidance. See Note 4 for additional information regarding the Merger.

~~In August 2016,~~lifetime expected credit losses, which the FASB ~~issued~~believes will result in more timely recognition of such losses. ASU ~~2016-15,~~ ~~Statement of Cash Flows-Classification of Certain Cash Receipts and Cash Payments. The objective of this update is to address eight specific cash flow issues in order to reduce the existing diversity in practice. ASU 2016-15 is~~2016-13 was effective for ~~the~~ annual periods beginning after December 15, ~~2017,~~2019 and interim periods within those annual periods. The standard was adopted ~~for this interim period ended March 31, 2018~~on January 1, 2020 and did not have a material impact on the ~~Company's~~Company’s disclosures and financial statements.

~~In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases~~. The objective of this update is to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and disclosing key information about leasing arrangements. ASU 2016-02 is effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The Company has performed an initial assessment by compiling and analyzing contracts and leasing arrangements that may be affected. The Company is still evaluating the impact of adopting this standard.

~~In May 2014, the FASB issued ASU 2014-09,~~ ~~Revenue from Contracts with Customers.~~ The objective of this update is to clarify the principles for recognizing revenue and to develop a common revenue standard. The FASB subsequently issued ASU 2015-14, ASU 2016-08, ASU 2016-10, ASU 2016-12 and ASU 2016-20, which provided additional implementation guidance and deferred the effective date of ASU 2014-09. The standard is effective for annual reporting periods beginning after December 15, 2017, and interim periods within those annual periods. The standard was adopted for this interim period ended March 31, 2018 using the modified retrospective transition method which was applied to contracts in place at the date of adoption. The Company is netting some additional gathering, transportation and processing expenses against its oil, gas and NGL production revenues. However, the cash flow and timing of the Company's revenue is not impacted and there is therefore no impact on the Company's net income (loss) or net income (loss) per common share. The standard also requires additional footnote disclosures. See the "~~Revenue Recognition"~~ ~~section above for additional disclosures.~~

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

Table of Contents


	Three Months Ended March 31,							Nine Months Ended September 30,
	2018			2017				2020		2019
	(in thousands)							(in thousands)
Cash paid for interest	$	395		$	430		Cash paid for interest	$	29,357	$	29,168
Cash paid for income taxes	—			—			Cash paid for income taxes	0		0
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties	67,047			36,976
Cash paid for amounts included in the measurements of lease liabilities:							Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases							Cash paid for operating leases	1,555		970
Non-cash operating activities:							Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations							Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)(2)							Operating leases (1)(2)	853		14,955
Non-cash investing and financing activities:							Non-cash investing and financing activities:

Accounts payable and accrued liabilities - oil and gas properties							Accounts payable and accrued liabilities - oil and gas properties	5,907		44,970

Change in asset retirement obligations, net of disposals	7,513			9,395			Change in asset retirement obligations, net of disposals	(486)		(5,443)
Retirement of treasury stock	(1,462		)	(967		)	Retirement of treasury stock	(668)		(1,725)
Properties exchanged in non-cash transactions	—			11,790			Properties exchanged in non-cash transactions	4,753		4,561
Issuance of common stock for Merger	484,000			—

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

~~4. Mergers~~

~~Merger with Fifth Creek Operating Company, LLC~~

On March 19, 2018, the Company completed the Merger with Fifth Creek. Assets acquired include approximately 81,000 net acres in Weld County in the DJ Basin, substantially all of which are operated, and 62 producing standard-length lateral wells and 10 producing extended-reach lateral wells.

As a result of the Merger, the Company recorded additional net proved reserves of approximately 9.3 MMBoe, of which approximately 4.7 MMBoe are proved developed reserves and 4.6 MMBoe are proved undeveloped reserves, as of March 31, 2018.

(2)The ~~Merger was effected through the issuance of 100,000,000 shares of the Company's common stock, with a fair value of $484.0 million on the date of closing, and the repayment of $53.9~~nine months ended September 30, 2019 included $14.0 million of ~~Fifth Creek debt. In connection~~right-of-use assets established with the ~~Merger, the Company incurred costs~~adoption of approximately $13.5 million to date of severance, consulting, advisory, legal and other merger-related fees, of which $4.8 million and $8.7 million were included in the Company's Unaudited Consolidated Statement of Operations for the three months ended March 31, 2018 and in the Company's Consolidated Statement of Operations for the year ended December 31, 2017, respectively.

~~Purchase Price Allocation~~

The transaction has been accounted for as a business combination, using the acquisition method, with the Company being the acquirer for accounting purposes. The following table represents the preliminary allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the fair values at the acquisition date. We expect to complete the purchase price allocation during the 12-month period following the acquisition date, during which time the value of the assets and liabilities may be revised as appropriate. The following table sets forth our preliminary purchase price allocation:

March 19, 2018
(in thousands)
Purchase Price:
Fair value of common stock issued $ 484,000
Plus: Repayment of Fifth Creek debt 53,900
Total purchase price 537,900

Plus Liabilities Assumed:
Accounts payable and accrued liabilities 24,469
Current unfavorable contract 2,651
Other current liabilities 13,852
Asset retirement obligations 7,361
Long-term deferred tax liability 137,111
Long-term unfavorable contract 4,449
Other noncurrent liabilities 2,354
Total purchase price plus liabilities assumed $ 730,147

Fair Value of Assets Acquired:
Cash 543
Accounts receivable 8,019
Oil and Gas Properties:
Proved oil and gas properties 105,702
Unproved oil and gas properties 607,526
Asset Retirement Obligations 7,361
Furniture, equipment and other 931
Other noncurrent assets 65
Total asset value $ 730,147

The fair value measurements of oil and natural gas properties and asset retirement obligations are based on inputs that are not observable in the market and therefore represent Level 3 inputs. The fair values of proved oil and natural gas properties and asset retirement obligations were measured using valuation techniques that convert future cash flows to a single discounted amount. Significant inputs to the valuation of oil and natural gas properties included estimates of: (i) recoverable reserves; (ii) production rates; (iii) future operating and development costs; (iv) future commodity prices; and (v) a market-based weighted average cost of capital rate. The fair value of unproved properties was determined using a market approach utilizing recent transactions of a similar nature in the same basin. These inputs required significant judgments and estimates by management at the time of the valuation and are the most sensitive to possible future changes.

The results of operations attributable to the merged companies are included in the Unaudited Consolidated Statements of Operations beginning on March 19, 2018. The Company generated revenues of approximately $2.1 million and expenses of approximately $1.8 million from the Fifth Creek assets during the period March 19, 2018 to March 31, 2018.

~~Pro Forma Financial Information~~

The following pro forma condensed combined financial information was derived from the historical financial statements of the Company and Fifth Creek and gives effect to the acquisition as if it had occurred onASC 842, Leases, effective January 1, 2017. The below information reflects pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the repayment of Fifth Creek's debt (ii) depletion of Fifth Creek's fair-valued proved crude oil and natural gas properties, and (iii) the estimated tax impacts of the pro forma adjustments.2019.

Additionally, pro forma earnings for the three months ended March 31, 2018 were adjusted to exclude merger-related costs of $4.8 million incurred by the Company and $4.0 million incurred by Fifth Creek for the three months ended March 31, 2018.

The pro forma results of operations do not include any cost savings or other synergies that may result from the acquisition or any estimated costs that have been or will be incurred by us to integrate the Fifth Creek assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

Three Months Ended March 31,
2018 2017
(in thousands, except per share data)
Revenues $ 96,742
$ 89,688
Net Income (Loss) and Comprehensive Income (Loss) (24,104 ) (10,674 )
Net Income (Loss) per Common Share, Basic and Diluted (0.12 ) (0.06 )

5.4. Long-Term Debt

The ~~Company's~~Company’s outstanding debt is summarized below:

As of March 31, 2018 As of December 31, 2017
Maturity Date Principal Debt Issuance Costs
Carrying
Amount
Principal Debt Issuance Costs
Carrying
Amount
(in thousands)
Amended Credit Facility April 8, 2020 $ —
$ —
$ —
$ —
$ —
$ —
7.0% Senior Notes ⁽¹⁾
October 15, 2022 350,000
(3,837 ) 346,163
350,000
(4,033 ) 345,967
8.75% Senior Notes ⁽²⁾
June 15, 2025 275,000
(4,919 ) 270,081
275,000
(5,080 ) 269,920
Lease Financing Obligation ⁽³⁾
August 10, 2020 2,212
—
2,212
2,328
(2 ) 2,326
Total Debt $ 627,212
$ (8,756 ) $ 618,456
$ 627,328
$ (9,115 ) $ 618,213
Less: Current Portion of Long-Term Debt ⁽⁴⁾
2,212
—
2,212
469
—
469
Total Long-Term Debt $ 625,000
$ (8,756 ) $ 616,244
$ 626,859
$ (9,115 ) $ 617,744


		As of September 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Debt Issuance Costs		Carrying Amount		Principal		Debt Issuance Costs		Carrying Amount
		(in thousands)
Credit Facility (1)	September 14, 2023	$	140,000	$	0	$	140,000	$	140,000	$	0	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,744)		348,256		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,202)		271,798		275,000		(3,717)		271,283
Total Long-Term Debt		$	765,000	$	(4,946)	$	760,054	$	765,000	$	(6,089)	$	758,911


~~(1)~~	The aggregate estimated fair value of the 7.0% Senior Notes was approximately $346.9 million and $356.1 million as of March 31, 2018 and December 31, 2017, respectively, based on reported market trades of these instruments.


~~(2)~~	The aggregate estimated fair value of the 8.75% Senior Notes was approximately $297.8 million and $305.3 million as of March 31, 2018 and December 31, 2017, respectively, based on reported market trades of these instruments.


~~(3)~~	The aggregate estimated fair value of the Lease Financing Obligation was approximately $2.0 million and $2.1 million as of March 31, 2018 and December 31, 2017, respectively. As there is no active, public market for the Lease Financing Obligation, the aggregate estimated fair value was based on market-based parameters of comparable term secured financing instruments.


~~(4)~~	The current portion of long-term debt includes the current portion of the Lease Financing Obligation. The Company has elected to exercise the early buyout option pursuant to which the Company will purchase the equipment for $1.8 million on February 10, 2019.

~~Amended~~ (1)The maturity date of the Credit Facility could be accelerated to July 16, 2022. See discussion below.

Credit Facility

~~The Amended~~On May 21, 2020, the Company’s Credit Facility ~~had commitments from 13 lenders~~was amended, which decreased the aggregate elected commitment amount and athe borrowing base offrom $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 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 $140.0 million outstanding under the Credit Facility as of ~~March~~both September 30, 2020 and December 31, ~~2018. As~~2019. The Company’s available borrowing capacity under the Credit Facility as of September 30, 2020 was $87.7 million, after taking into account the $50.0 million minimum availability requirement and $22.3 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under a contractual ~~obligation, a $26.0~~obligations. While the stated maturity date in the Credit Facility is September 14, 2023, the maturity date is accelerated if the Company has more than $100.0 million ~~letter~~ of ~~credit has been issued~~“Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the 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 Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

On November 2, 2020, as part of the Company’s regular semi-annual redetermination, the Credit Facility was amended, which, among other things, reduced the Company’s aggregate elected commitment amount to $185.0 million, reduced the

Table of Contents

borrowing base to $200.0 million and removed the provisions requiring availability under the ~~Amended~~ Credit Facility ~~which reduced~~to be at least $50.0 million. In addition, provisions were amended to disallow the ~~available borrowing capacity~~Company from incurring any additional indebtedness.

As of May 21, 2020, interest rates on outstanding loans under the ~~Amended~~ Credit Facility asare either adjusted LIBOR plus applicable margins of ~~March 31, 2018~~2.5% to ~~$274.0 million. There were no borrowings under~~3.5% or an alternate base rate, which is generally the ~~Amended Credit Facility in 2018 to date or in 2017.~~

~~Interest rates are LIBOR~~prime rate, plus applicable margins of 1.5% to 2.5% ~~or ABR plus 0.5% to 1.5%~~, and the unused commitment fee is ~~between 0.375%~~0.5%. The applicable margins and ~~0.5%~~the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Credit Facility was 3.3% and 4.1% for the three months ended September 30, 2020 and 2019, respectively, and 3.2% and 4.1% for the nine months ended September 30, 2020 and 2019, respectively.

The borrowing base under the ~~Amended~~ Credit Facility is determined at the discretion of the lenders ~~based on the collateral value of the Company's proved reserves that have been mortgaged to the lenders,~~ and is subject to regular ~~re-~~

~~determinations on or about~~redetermination in April 1 and October 1 of each year, as well as following any property sales. ~~On May 1, 2018, the Company's~~The lenders can also request an interim redetermination during each six month period. The borrowing base ~~was re-affirmed at $300.0 million based on Bill Barrett's proved reserves in place at December 31, 2017 and the Company's commodity hedge position. Borrowing bases are~~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~~the reserves calculated using future commodity pricing provided by the ~~Company's~~ lenders, as well as any other outstanding debt. ~~Lower commodity prices could result in a decreased borrowing base.~~

The ~~Amended~~Company has financial covenants associated with its Credit Facility ~~contains certain financial covenants.~~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. IfHowever, as discussed in the “Going Concern” section in Note 2, based on the Company’s financial projections for the twelve month period following the issuance date of these interim consolidated financial statements, it is probable the Company ~~fails~~will breach a financial covenant in the Company’s Credit Facility in the second quarter of 2021. If this breach were to ~~comply with~~occur and the ~~covenants or other terms of any agreements governing~~Company does not receive a waiver from the ~~Company's debt, the Company's~~ lenders, and holders of the Company's senior notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company's financial condition.

~~7.0% Senior Notes Due 2022~~

The Company's $350.0 million aggregate principal amount of 7.0% Senior Notes mature on October 15, 2022 at par, unless earlier redeemed or purchased by the Company. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the ~~Company's other existing~~amount borrowed under the Credit Facility will become due, and ~~future~~cross-defaults will occur under the indentures to the Company’s senior ~~unsecured indebtedness, including~~notes. Further, if the ~~8.75% Senior Notes.~~

~~The 7.0% Senior Notes became redeemable~~Company’s independent auditor includes an explanatory paragraph regarding the Company’s ability to continue as a “going concern” in its report on our financial statements for the year ending December 31, 2020, this would accelerate a default under the Company’s Credit Facility to the first quarter of 2021 at the ~~Company's option on October 15, 2017~~time the Company’s financial statements for the year ending December 31, 2020 are filed and, in turn, result in cross-default under the indentures to the senior notes at a redemption price of 103.500% of the principal amount. The redemption price will decrease to 102.333%, 101.167% and 100.000% of the principal amount in 2018, 2019 and 2020, respectively. The 7.0% Senior Notes include certain covenants that ~~limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends.~~time as well. The Company ~~is currently~~does not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in ~~compliance with all covenants and has complied with all covenants since issuance.~~the event of default.

~~8.75%~~ Senior Notes ~~Due 2025~~

The Company's $275.0 million aggregate principal amount of 8.75% Senior Notes mature on June 15, 2025 at par, unless earlier redeemed or purchased by the Company. Interest is payable in arrears semi-annually on June 15 and December 15 of each year. The 8.75% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company's other existing and future senior unsecured indebtedness, including the 7.0% Senior Notes.

The 8.75% Senior Notes will become redeemable at the Company's option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified "make-whole" premium. The 8.75% Senior Notes include certain covenants that limit the Company's ability to incur additional indebtedness, make restricted payments, create liens or sell assets and that generally prohibit the Company from paying dividends. The Company is currently in compliance with all covenants and has complied with all covenants since issuance.

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 2018 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. AIn addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of ~~HighPoint Operating Corporation is~~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 ~~guarantor~~joint and several basis, fully and unconditionally guarantee the debt securities of the ~~Senior Notes.~~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 ~~HighPoint Operating Corporation~~Subsidiary Issuer and the ~~subsidiary guarantor,~~Subsidiary Guarantor, including limitations on the ability ~~of HighPoint Operating Corporation~~ to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to ~~High Point Resources Corporation,~~the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor. HighPoint ~~Resources Corporation.~~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. However, the Credit Facility restricts the Company’s ability to repurchase the notes in open market purchases.

~~Lease Financing Obligation Due 2020~~

The Company has a lease financing obligation with a balance of $2.2 million as of March 31, 2018 resulting from the Company's sale and subsequent lease back of certain compressors and related facilities owned by the Company (the "Lease Financing Obligation"). The Lease Financing Obligation expires on August 10, 2020, and the Company has the option to purchase the equipment at the end of the lease term for the then current fair market value. The Lease Financing Obligation also contains an early buyout option pursuant to which the Company will purchase the equipment for $1.8 million on February 10, 2019. The lease payments related to the equipment are recognized as principal and interest expense based on a weighted average implicit interest rate of 3.3%. See Note 12 for a discussion of aggregate minimum future lease payments.

6.5. Asset Retirement Obligations

A reconciliation of the ~~Company's~~Company’s asset retirement obligations for the ~~three~~nine months ended ~~March 31, 2018~~September 30, 2020 is as follows (in thousands):

As of December 31, 2017 $ 17,586
Liabilities incurred ⁽¹⁾
7,795
Liabilities settled (282 )
Accretion expense 251
Revisions to estimate —
As of March 31, 2018 $ 25,350
Less: Current asset retirement obligations 1,443
Long-term asset retirement obligations $ 23,907


As of December 31, 2019	$	25,709
Liabilities incurred	519
Liabilities settled	(1,252)
Disposition of properties	(143)
Accretion expense	1,326
Revisions to estimate	390
As of September 30, 2020	$	26,549

~~(1)~~Less: Current asset retirement obligations	~~Includes~~ 2,136
Long-term asset retirement obligations	$~~7.4 million~~ ~~associated with properties acquired in the Merger during the~~ ~~three~~ ~~months ended~~ ~~March 31, 2018. See Note 4 for additional information regarding this Merger.~~	24,413

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~~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 ~~our consolidated balance sheet.~~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'~~counterparties’ valuations to assess the reasonableness of its own valuations. The Company currently utilizes an independent third party to perform the valuation.

Table of Contents

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~~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 September 30, 2020
Financial Assets

Deferred compensation plan	$	1,220	$	0	$	0	$	1,220
Commodity derivatives	0		58,048		0		58,048
Financial Liabilities
Commodity derivatives	0		7,069		0		7,069
As of December 31, 2019
Financial Assets

Deferred compensation plan	$	2,033	$	0	$	0	$	2,033
Commodity derivatives	0		8,890		0		8,890
Financial Liabilities
Commodity derivatives	0		10,056		0		10,056

Level 1 Level 2 Level 3 Total
(in thousands)
As of March 31, 2018
Financial Assets
Cash equivalents $ 196,710
$ —
$ —
$ 196,710
Deferred compensation plan 1,880
—
—
1,880
Commodity derivatives —
1,281
—
1,281
Financial Liabilities
Commodity derivatives —
45,708
—
45,708
As of December 31, 2017
Financial Assets
Cash equivalents 271,027
—
—
271,027
Deferred compensation plan 1,749
—
—
1,749
Commodity derivatives —
656
—
656
Financial Liabilities
Commodity derivatives —
25,714
—
25,714

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 ~~our~~the Company’s consolidated balance sheets. The following methods and assumptions were used to estimate the fair values:

Oil and gas properties –~~Oil~~ Proved oil and natural gas ~~property costs~~properties are evaluated for impairment on a quarterly basis or whenever events and ~~reduced to fair~~circumstances indicate that a decline in the recoverability of their carrying value ~~when there is an indication that~~may have occurred. Whenever the Company concludes the carrying ~~costs~~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.

~~Information~~ 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 ~~impaired assets is as follows:~~significant unobservable inputs, categorized within Level 3 of the fair value hierarchy, that were used in the fair value measurement.

Table of Contents

Level 1 Level 2 Level 3
Net Book
Value ⁽¹⁾
Impairment
Loss
(in thousands)
As of March 31, 2018
Proved and unproved properties $ —
$ —
$ —
$ —
$ —
As of December 31, 2017
Uinta Basin oil and gas properties⁽²⁾
—
—
106,587
144,532
37,945
DJ Basin unproved properties ⁽³⁾
—
—
18,832
20,887
2,055
Piceance Basin unproved properties ⁽⁴⁾
—
—
—
9,098
9,098


~~(1)~~Level 3 Unobservable Inputs			~~Amount represents net book value at the date~~			As of ~~assessment.~~March 31, 2020

Price (1)
~~(2)~~Oil (per Bbl)			~~The Company recognized a non-cash impairment charge associated with the Company's Uinta Oil Program proved properties during the year ended December 31, 2017. The properties were sold on December~~			$29 ~~2017.~~to $60

Gas (per MMbtu)		$2.03 to $2.52
NGL (percentage of oil price)		24% to 31%
Reserve adjustment factors
~~(3)~~PDP	As a result of having no future plans to develop certain acreage and/or estimated market values below carrying value, the Company recognized non-cash impairment charges of $2.1 million associated with certain non-core unproved properties in the DJ Basin during the year ended December 31, 2017.

	100%
~~(4)~~PDN	As a result of having no future plans to develop certain acreage and/or estimated market values below carrying value, the Company recognized non-cash impairment charges of $9.1 million associated with certain unproved properties in the Cottonwood Gulch area of the Piceance Basin during the year ended December 31, 2017.	95%
Discount rate		11%

~~Purchase~~

(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 ~~allocation~~ –~~The Merger~~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~~accounted~~ included in impairment and abandonment expense on the Unaudited Statement of Operations for ~~as a business combination, using~~ the ~~acquisition method. The allocation~~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 ~~total purchase price~~Company’s unproved oil and gas properties. The third party used the market approach utilizing sales prices of comparable properties to ~~the identifiable assets acquired and the liabilities assumed was based on the fair values at the acquisition date. See Note 4 for additional information regarding~~determine the fair value of the ~~Merger.~~unproved oil and gas properties.

No properties were measured at fair value during the three months ended June 30, 2020 or September 30, 2020.

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 ~~values~~value of the ~~Company's fixed rate~~ 7.0% Senior Notes was approximately $85.3 million and $335.0 million as of September 30, 2020 and December 31, 2019, respectively. The estimated fair value of the 8.75% Senior Notes ~~totaled $644.7~~was approximately $68.1 million and $251.2 million as of ~~March~~September 30, 2020 and December 31, ~~2018.~~2019, respectively. The fair values of the ~~Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $661.4 million as of December 31, 2017. The fair values of the Company's~~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 or Lease Financing Obligation.~~Facility. The recorded value of the ~~Amended~~ Credit Facility ~~approximates~~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~~Company’s borrowing base utilization. The ~~Amended~~ Credit Facility had a balance of ~~zero~~$140.0 million as of ~~March 31, 2018~~both September 30, 2020 and December 31, 2017. The Lease Financing Obligation fair values of $2.0 million and $2.1 million as of March 31, 2018 and December 31, 2017, respectively, are measured based on market-based parameters of comparable term secured financing instruments.2019. The fair value measurements for the ~~Amended~~ Credit Facility ~~and Lease Financing Obligation~~ represent Level 2 inputs.

8.7. 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, swaption and cashless collar contracts related to the sale of a portion of the ~~Company's~~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. A cashless collar establishes a floor and a ceiling price, which allows the Company to receive the difference between the floor price and the variable market price if the variable market price is below the floor price. However, the Company will pay the difference between the ceiling price and the variable market price if the variable market price is above the ceiling. No amounts are paid or received if the variable market price is between the floor and ceiling prices. 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 price (“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

Table of Contents

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 March 31, 2018
Balance Sheet Gross Amounts of
Recognized Assets Gross Amounts
Offset in the Balance
Sheet Net Amounts of
Assets Presented in
the Balance Sheet
(in thousands)
Derivative assets $ 949
$ (949 )
⁽¹⁾
$ —
Deferred financing costs and other noncurrent assets 332
(332 )
⁽¹⁾
—
Total derivative assets $ 1,281
$ (1,281 ) $ —

Gross Amounts of
Recognized Liabilities Gross Amounts
Offset in the Balance
Sheet Net Amounts of
Liabilities Presented in
the Balance Sheet
(in thousands)
Derivative liabilities $ (36,815 ) $ 949
⁽¹⁾
$ (35,866 )
Derivatives and other noncurrent liabilities (8,893 ) 332
⁽¹⁾
(8,561 )
Total derivative liabilities $ (45,708 ) $ 1,281
   $ (44,427 )


As of December 31, 2017
Balance Sheet Gross Amounts of
Recognized Assets Gross Amounts
Offset in the Balance
Sheet Net Amounts of
Assets Presented in
the Balance Sheet
(in thousands)
Derivative assets $ 594
$ (594 )
⁽¹⁾
$ —
Deferred financing costs and other noncurrent assets 62
(62 )
⁽¹⁾
—
Total derivative assets $ 656
$ (656 ) $ —

Gross Amounts of
Recognized Liabilities Gross Amounts
Offset in the Balance
Sheet Net Amounts of
Liabilities Presented in
the Balance Sheet
(in thousands)
Derivative liabilities $ (21,534 ) $ 594
⁽¹⁾
$ (20,940 )
Derivatives and other noncurrent liabilities (4,180 ) 62
⁽¹⁾
(4,118 )
Total derivative liabilities $ (25,714 ) $ 656
   $ (25,058 )


	As of September 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)	$	50,632	$	(3,643)	$	46,989
Derivative assets (noncurrent)	7,416		(2,825)		4,591
Total derivative assets	$	58,048	$	(6,468)	$	51,580

	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	$	(3,643)	$	3,643	$	0
Other noncurrent liabilities	(3,426)		2,825		(601)
Total derivative liabilities	$	(7,069)	$	6,468	$	(601)

	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)		0
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.~~

(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 ~~March 31, 2018,~~September 30, 2020, the Company had ~~financial instruments~~swap and swaption contracts in place to hedge the following volumes for the periods indicated:

Table of Contents


											October – December 2020			For the year 2021			For the year 2022
	April – December 2018			For the year 2019			For the year 2020				Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Swaps										Swaps
Oil (Bbls)	3,602,619	$	54.14	3,280,434	$	55.00	183,000	$	50.20	Oil (Bbls)	1,311,000	$	56.29	3,098,000	$	54.30	0	$	0
Natural Gas (MMbtu)	1,375,000	$	2.68	—	$	—	—	$	—	Natural Gas (MMbtu)	1,840,000	$	1.83	5,790,000	$	2.13	3,650,000	$	2.13

Oil Roll Swaps (1)										Oil Roll Swaps (1)
Oil (Bbls)										Oil (Bbls)	138,000	$	(1.47)	182,500	$	(0.25)	0	$	0
Swaptions										Swaptions
Oil (Bbls)										Oil (Bbls)	0	$	0	0	$	0	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 price. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.

As of September 30, 2020, the Company had cashless collars in place to hedge the following volumes for the periods indicated:


	October – December 2020					For the year 2021
	Derivative Volumes	Weighted Average Floor		Weighted Average Ceiling		Derivative Volumes	Weighted Average Floor		Weighted Average Ceiling
Cashless Collars

Natural Gas (MMbtu)	920,000	$	2.00	$	2.70	1,800,000	$	2.00	$	4.25

The ~~Company's~~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 ~~seven~~8 different counterparties as of ~~March 31, 2018.~~September 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 ~~these~~its counterparties.

It is the ~~Company's~~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~~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"~~(“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~~Company’s 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.

9.8. Income Taxes

~~On the date of the Merger, the Fifth Creek assets were acquired~~The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a ~~nontaxable transaction pursuant to Section 351 of~~tax return in accordance with the ~~Internal Revenue Code. Accordingly, a deferred tax liability of~~ ~~$137.1 million~~ ~~was recorded to reflect the difference between the fair value recorded and~~FASB’s rules on income taxes. The Company recognizes the tax ~~basis of the assets acquired and liabilities assumed.~~

~~The~~benefit from an uncertain tax ~~effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities as of March 31, 2018 and December 31, 2017 are presented below:~~

As of March 31, 2018 As of December 31, 2017
(in thousands)
Deferred tax assets:
Net operating loss carryforward $ 116,193
$ 170,536
Stock-based compensation 2,849
3,826
Deferred rent —
163
Deferred compensation 846
1,824
State tax credit carryforwards —
6,499
Financing obligation 678
705
Accrued expenses 325
248
Investment in partnership 1,255
—
Derivative instruments 10,945
6,158
Other assets 2,314
228
Less: Valuation allowance (51,719 ) (114,530 )
Total deferred tax assets 83,686
75,657
Deferred tax liabilities:
Oil and gas properties (220,705 ) (75,409 )
Prepaid expenses (92 ) (248 )
Total deferred tax assets (liabilities) (220,797 ) (75,657 )
Net deferred tax assets (liabilities) $ (137,111 ) $ —

In connection with the Merger, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code. As a result of the ownership change, the Company's ability to use pre-change net operating losses ("NOLs") and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change. The Company's annual limitation amount is approximately $11.7 million. The Company has reduced its Federal and state net operating losses by $274.6 million and $10.0 million, respectively, and eliminated its state tax credits by $8.2 million to reflect the expected impact of the Section 382 limitation. Deferred tax assets

~~and the corresponding valuation allowance have been reduced by $64.5 million for the expected tax effect of the Section 382 limitation. As of~~ ~~March 31, 2018, the Company projected approximately $471.1 million and $471.5 million of Federal and state NOLs, respectively. The Federal NOLs begin to expire in 2025 and the state NOLs begin to expire in 2029.~~

On December 22, 2017, Congress signed into law the Tax Cut and Jobs Act of 2017 ("TCJA"). The TCJA includes significant changes to the U.S. corporate tax system including a rate reduction from 35% to 21% beginning in January of 2018. Accordingly, the 21% Federal tax rate is utilized in computing the Company's annualized effective tax rate. Other provisions of TCJA include the elimination of the corporate alternative minimum tax, acceleration of depreciation for U.S. tax purposes, limitations on deductibility of interest expense, expanded Section 162(m) limitations on the deductibility of officer's compensation, the elimination of NOL carrybacks, and indefinite carryforwards on losses generated after 2017, subject to restrictions on their utilization.

~~In assessing the ability to realize the benefit of the deferred tax assets, management must consider whether~~position only if it is more likely than not that ~~some portion~~the tax position will be sustained upon examination by the taxing authorities. During the three and nine months ended September 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 ~~all~~penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2020 and 2019.

Income tax benefit for the three and nine months ended September 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 ~~the~~ deferred tax ~~assets will not be realized. Management~~asset valuation allowances. For the three and nine months ended September 30, 2020, the Company recognized $0.6 million and $95.9 million of income tax benefit, respectively. For the three and nine months ended September 30, 2019, the Company recognized $4.3 million of income tax expense and $25.3 million of income tax benefit, respectively. The Company considers all available evidence (both positive and negative) ~~in determining~~to estimate whether ~~a valuation allowance is required.~~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. ~~In regard~~For the three and nine months ended September 30, 2020, the Company determined that there would not be sufficient future taxable income to ~~the Company's~~use existing deferred tax assets and has recorded a valuation allowance against the existing net deferred tax assets. For the nine months ended September 30, 2020, the Company ~~considered all available evidence~~has recorded a deferred tax liability of $1.6 million for projected taxable income in ~~assessing~~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 ~~need for a valuation allowance.~~reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.

~~10. Stockholders' Equity~~

~~Common and Preferred Stock.~~ ~~The Company's authorized capital structure consists of~~ ~~75,000,000~~ ~~shares of preferred stock, par value,~~ ~~$0.001~~ ~~per share, and~~ ~~400,000,000~~ ~~shares of common stock, par value~~ ~~$0.001~~ ~~per share. In March 2018, the Company increased the number of authorized shares of common stock from~~ ~~300,000,000~~ to ~~400,000,000~~ ~~with the Amended and Restated Certificate of Incorporation. There are no issued and outstanding shares of preferred stock.~~

In ~~March 2018, the Company completed the Merger with Fifth Creek. Pursuant~~response to the ~~Merger Agreement, each share~~COVID-19 pandemic, President Trump signed the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”) on March 27, 2020. Several of ~~Bill Barrett common stock, par value $0.001 per share (the "BBG Common Stock"), issued~~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 ~~outstanding immediately~~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 the closing of the Merger was converted into one share of the Company's common stock and all outstanding equity interests in Fifth Creek, in the aggregate, were converted into 100,000,000 shares of the Company's common stock. In addition, all options to purchase shares of BBG Common Stock and all common stock awards and performance-based cash unit awards relating to BBG Common Stock that were outstanding immediately prior to the closing of the Merger were generally converted into corresponding awards relating to shares of the Company's common stock on the same terms and conditions (excluding performance conditions) as applied prior to the closing of the Merger (with 2016 and 2017 Program performance-based cash units converting into time-based common stock awards based on actual performance for the 2016 program and target performance for the 2017 program through the closing date). See Note 11 for additional information on equity compensation.January 1, 2021.

In March 2018, the Company terminated the Equity Distribution Agreement (the "Agreement"), dated as of June 2015, by and between the Company and Goldman, Sachs and Co. (the "Manager"). The Agreement was terminable at will upon written notification by the Company with no penalty. Pursuant to the terms of the Agreement, the Company was permitted to sell, from time to time through or to the Manager, shares of its common stock having an aggregate gross sales price of up to $100.0 million. Sales of the shares, if any, would be made by means of ordinary brokers' transactions through the facilities of the New York Stock Exchange, at market prices, in block transactions, to or through a market maker, through an electronic communications network or as otherwise agreed by the Company and the Manager. As of March 31, 2018, no shares had been sold pursuant to the Agreement.

~~11.~~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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
	(in thousands)
Nonvested common stock (1)	$	996	$	1,992	$	3,296	$	5,321
Nonvested common stock units (1)	30		283		512		895
Nonvested performance cash units (2)(3)	(55)		(130)		(831)		947
Total	$	971	$	2,145	$	2,977	$	7,163

Three Months Ended March 31,
2018 2017
(in thousands)
Nonvested common stock ⁽¹⁾
$ 1,330
$ 1,450
Nonvested common stock units⁽¹⁾
170
170
Nonvested performance-based shares ⁽¹⁾
—
469
Nonvested performance cash units ⁽²⁾⁽³⁾
(73 ) (961 )
Total $ 1,427
$ 1,128
(1)Unrecognized compensation expense as of September 30, 2020 was $4.0 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.6 years.


~~(1)~~	Unrecognized compensation cost as of March 31, 2018 was $10.4 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 2.1 years.

~~(2)~~

The nonvested performance-based cash units are accounted for as liability awards with $1.4 million in accounts payable and accrued liabilities as of December 31, 2017 and $0.2 million and $3.0 million in derivatives and other noncurrent liabilities as of March 31, 2018 and December 31, 2017, respectively, in the Unaudited Consolidated Balance Sheets. The decrease in liability was due to the closing of the Merger and the resulting conversion of the 2016 and 2017 Programs from liability awards to equity awards. See the 2016 Program and 2017 Program below for additional information on the conversion.

~~(3)~~

Liability awards are fair valued at each reporting date. For the three months ended March 31, 2018, the weighted average fair value share price decreased from $5.10 as of December 31, 2017 to $5.08 as of March 31, 2018. Prior to the 2016 and 2017 Program conversion discussed below, the weighted average fair value share price was $4.63 resulting in a decrease in expense offset by an increase in expense for the 2018 Program. See "2016 Program" and "2017 Program" below for additional information regarding the conversion. For the three months ended March 31, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.55 as of March 31, 2017.

(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 September 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~~Company’s various stock compensation plans. A summary of the ~~Company's~~Company’s nonvested common stock awards for the three and nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017~~2019 is presented below:

Table of Contents


										Three Months Ended September 30, 2020			Three Months Ended September 30, 2019
Nonvested Common Stock Awards									Nonvested Common Stock Awards	Shares (1)	Weighted Average Grant Date Fair Value (1)		Shares (1)	Weighted Average Grant Date Fair Value (1)
Outstanding at July 1,									Outstanding at July 1,	63,374	$	103.45	68,122	$	194.11
Granted									Granted	0	0		120	62.50

Vested									Vested	(2,384)	208.62		(7,120)	209.45
Forfeited or expired									Forfeited or expired	(2,034)	61.09		(1,462)	239.81
Outstanding at September 30,									Outstanding at September 30,	58,956	100.60		59,660	190.90

	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017					Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
Nonvested Common Stock Awards	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value		Nonvested Common Stock Awards	Shares (1)	Weighted Average Grant Date Fair Value (1)		Shares (1)	Weighted Average Grant Date Fair Value (1)
Outstanding at January 1,	1,394,868		$	7.00	1,169,099		$	9.33	Outstanding at January 1,	59,369	$	190.74	58,243	$	263.50
Granted	796,423		5.00		749,227		6.10		Granted	40,572	57.00		36,954	131.95
Modified ⁽¹⁾	1,146,305		4.84		—		—
Vested	(652,208	)	8.35		(468,603	)	10.55		Vested	(33,754)	212.35		(33,711)	249.29
Forfeited or expired	(27,853	)	6.62		(7,784	)	9.53		Forfeited or expired	(7,231)	74.39		(1,826)	241.44
Outstanding at March 31,	2,657,535		5.14		1,441,939		7.25
Outstanding at September 30,									Outstanding at September 30,	58,956	100.60		59,660	190.90


~~(1)~~	Due to the closing of the Merger, the 2016 and 2017 Performance Cash Programs were converted from nonvested performance-based cash units to nonvested common stock awards, resulting in an increase of nonvested common stock awards for the three months ended March 31, 2018.

(1)All share and per share information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

A summary of the ~~Company's~~Company’s nonvested common stock unit awards for the three and nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017~~2019 is presented below:


	Three Months Ended September 30, 2020			Three Months Ended September 30, 2019
Nonvested Common Stock Unit Awards	Units (1)	Weighted Average Grant Date Fair Value (1)		Units (1)	Weighted Average Grant Date Fair Value (1)
Outstanding at July 1,	12,185	$	86.22	15,922	$	163.61



Outstanding at September 30,	12,185	86.22		15,922	163.61

	Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
Nonvested Common Stock Unit Awards	Units (1)	Weighted Average Grant Date Fair Value (1)		Units (1)	Weighted Average Grant Date Fair Value (1)
Outstanding at January 1,	15,922	$	163.61	6,224	$	362.97
Granted	10,618	13.48		12,862	93.78
Vested	(12,767)	131.38		(3,164)	271.99
Forfeited or expired	(1,588)	12.69		0	0
Outstanding at September 30,	12,185	86.22		15,922	163.61

Three Months Ended March 31, 2018 Three Months Ended March 31, 2017
Nonvested Common Stock Unit Awards Units Weighted Average
Grant Date
Fair Value Units Weighted Average
Grant Date
Fair Value
Outstanding at January 1, 272,559
$ 6.37
147,167
$ 10.09
Granted 3,198
5.08
3,571
4.55
Vested (3,198 ) 5.08
(3,571 ) 4.55
Forfeited or expired —
—
—
—
Outstanding at March 31, 272,559
6.37
147,167
10.09
(1)All unit and per unit information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

A summary of the ~~Company's~~Company’s nonvested performance-based cash unit awards for the three and nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017~~2019 is presented below:

Table of Contents


										Three Months Ended September 30, 2020			Three Months Ended September 30, 2019
Nonvested Performance-Based Cash Unit Awards									Nonvested Performance-Based Cash Unit Awards	Units (1)	Weighted Average Fair Value (1)		Units (1)	Weighted Average Fair Value (1)
Outstanding at July 1,									Outstanding at July 1,	108,796			57,372

Forfeited or expired									Forfeited or expired	(7,714)			(5,851)
Outstanding at September 30,									Outstanding at September 30,	101,082	$	11.50	51,521	$	79.50

	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017					Nine Months Ended September 30, 2020			Nine Months Ended September 30, 2019
Nonvested Performance-Based Cash Unit Awards	Units		Weighted Average Fair Value		Units		Weighted Average Fair Value		Nonvested Performance-Based Cash Unit Awards	Units (1)	Weighted Average Fair Value (1)		Units (1)	Weighted Average Fair Value (1)
Outstanding at January 1,	1,548,083				942,326				Outstanding at January 1,	51,521			18,191
Granted	796,423				633,141				Granted	71,388			40,530
Performance goal adjustment ⁽¹⁾	11,289				—
Modified ⁽²⁾	(1,211,478	)			—
Vested	(286,652	)			—

Forfeited or expired	(61,242	)			(8,067	)			Forfeited or expired	(21,827)			(7,200)
Outstanding at March 31,	796,423		$	5.08	1,567,400		$	4.55
Outstanding at September 30,									Outstanding at September 30,	101,082	$	11.50	51,521	$	79.50


~~(1)~~	The 2015 Program vested at 104.1% in excess of target level and resulted in additional units vested in March 2018. These units are included in the vested line item for the three months ended March 31, 2018.

~~(2)~~

Due to the closing of the Merger, the 2016 and 2017 Performance Cash Programs were converted from nonvested performance-based cash units to nonvested common stock awards, resulting in a decrease in nonvested performance-based cash units for the three months ended March 31, 2018. The 2016 Program converted based on its performance through March 19, 2018, which resulted in 89% of the units converting to nonvested common stock awards or a reduction of 65,173 units converting to nonvested common stock awards.

(1)All unit and per unit information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

Performance Cash Program

~~2018~~2020 Program. In February ~~2018,~~2020, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the ~~"2018 Program"~~“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 ~~2021,~~2023, depending on the level at which the performance goal is achieved. The ~~performance-goal,~~performance goal, which will be measured over the ~~three-year~~three-year period ending December 31, ~~2020,~~2022, will be the ~~Company's~~Company’s total shareholder return ~~("TSR"~~(“TSR”) based on a matrix measurement of (1) the ~~Company's~~Company’s absolute performance and (2) the ~~Company's~~Company’s ranking relative to a defined peer ~~group's~~group’s individual TSRs ("(“Relative ~~TSR"~~TSR”). The ~~Company's~~Company’s absolute performance is measured against the December ~~29, 2017~~31, 2019 closing share price of ~~$5.13. If~~$84.50, which has been retroactively adjusted to reflect a 1-for-50 reverse stock split. For the ~~Company's~~portion of the program based on absolute performance, ~~is lower than the $5.13 share price,~~ the payout will be equal to the Company’s absolute TSR up to 100%, which is ~~zero~~the maximum payout for this portion. IfFor the ~~Company's absolute performance is greater than the $5.13 share price, the performance cash units will vest 1% for each 1% in growth, up to 150%~~portion of the ~~original grant. If~~program based on relative performance (i) if the ~~Company's~~Company’s Relative TSR is less than ~~the median,~~30%, the payout is ~~zero for this portion. If~~0 and (ii) if the ~~Company's~~Company’s Relative TSR is ~~above the median,~~30% or greater, the payout is equal to the ~~Company's~~Company’s percentile rank ~~above the median,~~ up to ~~50%~~100% of the original grant. The ~~Company's~~Company’s combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant.

10. Leases

A ~~total~~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 ~~796,423 units were granted under this program~~the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the ~~three months ended March 31, 2018.~~

~~2017 Program.~~ In February 2017, the Compensation Committee approved a performance cash program (the "2017 Program") granting performance cash units that would settle in cash and were accounted for as liability awards. In March 2018 upon the Merger closing, the 2017 Program was converted to a nonvested common stock award at 100%term of the ~~original award. At the time~~contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the ~~modification, 619,006 units were converted to 619,006 shares~~contract. For all leases, other than those that qualify for the short-term recognition exemption, the Company recognizes as of the ~~Company's nonvested common stock.~~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 ~~awards no longer have a performance criteria, but continue~~options are used to ~~have a service-based criteria through~~calculate right-of-use asset and lease liability balances when it is reasonably certain that the ~~cliff vest in February 2020.~~Company will exercise these options. The ~~conversion~~discount rate used to calculate the present value of the ~~performance-based liability award to a service-based equity award was accounted for as~~future minimum lease payments is the Company’s incremental borrowing rate.

~~a modification in accordance with ASC 718,~~ ~~Compensation - Stock Compensation~~. The Company ~~recorded an increase~~elected, for all classes of underlying assets, to ~~additional paid-in capital ("APIC")~~not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and ~~a decrease to derivative and other noncurrent liabilities of $0.9 million as of March 31, 2018~~instead, recognize the lease payments in the ~~Unaudited Consolidated Statement~~income statement on a straight-line basis over the lease term. The Company also elected, for certain classes of ~~Stockholders' Equity~~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 ~~respectively.~~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.

Table of Contents

~~2016 Program.~~ ~~In March 2016,~~

For the ~~Compensation Committee approved a performance cash program (the "2016 Program") granting performance cash units that would settle~~three and nine months ended September 30, 2020 and 2019, lease cost were as follows:


	Three Months Ended September 30,				Nine Months Ended September 30,
Lease Cost	2020		2019		2020		2019
	(in thousands)
Operating lease cost (1)(3)	$	531	$	576	$	1,570	$	1,693
Short-term lease cost (2)(3)	367		2,678		3,419		13,064
Variable lease cost (4)	347		154		1,040		154
Total lease cost	$	1,245	$	3,408	$	6,029	$	14,911

(1)Operating lease cost was primarily included in ~~cash~~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 ~~accounted for as liability awards. In March 2018 upon~~capitalized to property, plant and equipment on the ~~Merger closing, the 2016 Program was converted to a nonvested common stock award at 89%~~Unaudited Consolidated Balance Sheets.

(3)A portion of the ~~original award~~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 performance through March 19, 2018. At the time of the modification, 592,472 units were converted~~Company’s working interest, which varies from property to 527,299 shares of the Company's nonvested common stock. These awards no longer have a performance criteria, but continue to have a service-based criteria through the cliff vest in February 2019. The conversion of the performance-based liability awardproperty.

(4)Variable lease cost is related to a ~~service-based equity award was accounted for as a modification~~gathering agreement and is included in ~~accordance with ASC 718,~~ ~~Compensation - Stock Compensation. The Company recorded an increase~~oil, gas, and NGL production on the Unaudited Consolidated Statements of Operations.

Supplemental balance sheet information related to ~~APIC and a decrease to derivative and other noncurrent liabilities of $1.8 million~~leases as of ~~March~~September 30, 2020 and December 31, ~~2018~~2019, were as follows:


Operating Leases	As of September 30, 2020		As of December 31, 2019
	(in thousands)
Right-of-use assets (1)	$	9,821	$	9,287
Accumulated amortization (2)	(1,794)		(1,142)
Total right-of-use assets, net (3)	$	8,027	$	8,145
Current lease liabilities (4)	(1,955)		(1,287)
Noncurrent lease liabilities (5)	(12,425)		(13,195)
Total lease liabilities (3)	$	(14,380)	$	(14,482)
Weighted average remaining lease term
Operating leases (in years)	7.0		7.8
Weighted average discount rate
Operating leases	5.6%		5.6		%

(1)Included in furniture, equipment and other in the Unaudited Consolidated ~~Statement of Stockholders' Equity~~Balance Sheets.

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

~~2015 Program.~~ ~~In February 2015,~~(3)The difference between the ~~Compensation Committee approved a performance cash program (the "2015 Program") granting performance cash units that would settle in cash~~right-of-use assets and ~~were accounted for as liability awards. The performance-based awards were~~total lease liabilities is primarily related to ~~contingently vest in May 2018, depending on the level at which the performance goals were achieved. The performance goals,~~lease incentives and deferred rent balances, which were ~~measured over~~required to be netted against the ~~three year period ending~~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 September 30, 2020 and December 31, ~~2017, consisted~~2019 were as follows:

Table of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group's percentage calculation ("DCF per Debt Adjusted Share") (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals would vest at 25% or 50%, respectively, of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric were between the threshold and target levels or between the target and stretch levels, the vested number of units would be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics were not met, no units would vest. In any event, the total number of units that could vest would not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, any units that had not vested would be forfeited. A total of 422,345 units were granted under this program during the year ended December 31, 2015. All compensation expense related to the TSR metric would be recognized if the requisite service period was fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric would be based on the number of shares expected to vest at the end of the three year period. The Company modified the vesting date of these awards from May 2018 to March 2018. Based upon the Company's performance through 2017, 104.1% or 286,652 units of the 2015 Program vested in March 2018.Contents


	As of September 30, 2020		As of December 31, 2019
	(in thousands)
2020	$	678	$	2,056
2021	2,664		2,355
2022	2,367		2,044
2023	2,130		2,024
2024	2,078		2,078
Thereafter	7,576		7,577
Total	$	17,493	$	18,134
Less: Interest	(3,113)		(3,652)
Present value of lease liabilities	$	14,380	$	14,482

~~12.~~

11. Commitments and Contingencies

~~Lease Financing Obligation.~~ The Company has a Lease Financing Obligation with Bank of America Leasing & Capital, LLC as the lead bank as discussed in Note 5. The aggregate undiscounted minimum future lease payments, including both principal and interest components, are presented below. The Company has elected to exercise the early buyout option pursuant to which the Company will purchase the equipment for $1.8 million on February 10, 2019.

As of March 31, 2018
(in thousands)
2018 $ 403
2019 1,869
Thereafter —
Total $ 2,272

Firm Transportation Agreements. The Company is party to ~~two~~2 firm transportation contracts ~~through July 2021,~~ 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 1 firm pipeline transportation contract to provide capacity on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges through April 2025 regardless of the amount of pipeline capacity utilized by the Company.

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


	As of September 30, 2020
	(in thousands)
2020	$	6,399
2021	19,777
2022	13,064
2023	14,600
2024	14,640
Thereafter	4,799
Total	$	73,279

As of March 31, 2018
(in thousands)
2018 $ 13,784
2019 18,691
2020 18,691
2021 10,902
Thereafter —
Total $ 62,068

Gas Gathering and Processing ~~Agreement.~~Agreements. The Company is party to ~~one~~1 minimum volume commitment ~~through December 2021 which~~and 2 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 ~~those~~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~~Company’s future minimum ~~volume charges:~~charges under both types of agreements:


	As of September 30, 2020
	(in thousands)
2020	$	544
2021	3,778



Thereafter	0
Total	$	4,322

Table of Contents

As of March 31, 2018
(in thousands)
2018 $ 1,962
2019 2,365
2020 2,167
2021 1,996
Thereafter —
Total $ 8,490

~~Lease and~~ Other Commitments.~~The Company leases office space, vehicles and certain office equipment under non-cancellable operating leases.~~ The Company has ~~various long-term~~1 drilling commitment with a joint interest partner that requires the Company to drill and complete 2 wells by July 2022 and 3 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 2 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. Due to a decline in activity, the Company does not anticipate utilizing the minimum volume for the year 2020 for one of the commitments and, therefore, recognized $0.5 million in unused commitments in the Unaudited Consolidated Statement of Operations during the three and nine months ended September 30, 2020. The Company also has non-cancellable agreements for ~~telecommunication~~information technology services. Future minimum annual payments under ~~lease and other~~these agreements are as follows:


	As of September 30, 2020
	(in thousands)
2020	$	579
2021	1,285
2022 (1)	11,485
2023 (1)	16,284

Thereafter	0
Total	$	29,633

As of March 31, 2018
(in thousands)
2018 $ 3,188
2019 1,817
2020 853
2021 458
2022 445
Thereafter 191
Total $ 6,952

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

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~~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.~~Operations, other than the following.

~~13. Guarantor Subsidiaries~~

The condensed consolidating financial information as of and for the periods ended March 31, 2018 presents the results of operations, financial position and cash flows of HighPoint Resources Corporation, or parent guarantor,Sterling Energy Investments LLC v. HighPoint Operating Corporation ~~(f/k/~~, 2020CV32034, District Court in Denver, Colorado. On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a ~~Bill Barrett), or subsidiary issuer, and Circle B Land Company, LLC,~~complaint against HighPoint Operating Corporation, a subsidiary guarantor, as well as the consolidating adjustments necessary to present HighPoint Resources Corporation's results on a consolidated basis. The parent guarantor and the subsidiary guarantor, on a joint and several basis, have fully and unconditionally guaranteed the debt

securities of the subsidiary issuer. The indentures governing those securities limit the ability of the subsidiary issuer and the subsidiary guarantor to pay dividends or otherwise provide funding to the parent guarantor.

~~Prior periods are presented under the structure~~ of the Company, ~~prior~~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 Purchase Agreement. The Company is seeking monetary damages in an amount not yet specified.

12. Subsequent Event

Reverse Stock Split. On October 20, 2020, the Company announced a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-50 and a proportionate reduction of the total number of authorized shares of common stock, which was approved by the stockholders at the Company’s Annual Meeting of Stockholders on April 28, 2020. The reverse stock split became effective on October 30, 2020, and the Company’s common stock was traded on a split-adjusted basis on the NYSE at the market open on that date. The par value of the common stock was not adjusted as a result of the reverse stock split.

The reverse stock split is intended to increase the per share trading price of the Company’s common stock to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, every 50 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled and paid out in cash. The reverse stock split reduced the number of shares of the Company’s outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares, subject to adjustment of the rounding of fractional shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 400,000,000 to 8,000,000 shares. All share and per share amounts in the consolidated financial statements and notes herein were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the ~~Merger, of which Circle B Land Company, LLC and Aurora Gathering, LLC (both 100% owned subsidiaries~~reduction in par value of the ~~Company)~~Company’s common stock to additional paid-in capital.

Table of Contents

Merger. On November 8, 2020, the Company and Bonanza Creek Energy, Inc., a Delaware corporation (“Bonanza Creek”), entered into a definitive merger agreement (“Merger Agreement”) to effectuate the strategic combination of Bonanza Creek and HighPoint. The transaction has been unanimously approved by the board of directors of each company. Under the terms of the Merger Agreement, Bonanza Creek has agreed to commence a registered exchange offer (the “Exchange Offer”). The Exchange Offer will be conditioned on a ~~joint~~minimum participation condition of not less than 95% of the aggregate outstanding principal amount of HighPoint senior unsecured notes (the “HighPoint Notes”) and ~~several basis, fully and unconditionally guaranteed~~not less than a majority of the ~~debt~~outstanding holders of ~~Bill Barrett,~~ the ~~parent issuer. On December 29, 2017,~~HighPoint Notes (the “Minimum Participation Condition”).

If the ~~Company completed~~Minimum Participation Condition is not met, HighPoint has agreed to solicit a prepackaged plan of reorganization under Chapter 11 of the ~~sale of its remaining assets~~United States Bankruptcy Code in the ~~Uinta Basin, which included~~United States Bankruptcy Court for the ~~sale~~[District of ~~Aurora Gathering, LLC.~~

~~For~~Delaware] (the “Court,” and such plan, the ~~purpose of the following financial information, investments in subsidiaries are reflected in accordance~~“Prepackaged Plan”). HighPoint will file voluntary petitions under Chapter 11 with the ~~equity method~~Court to effectuate the Prepackaged Plan, under which the companies will seek to consummate the merger.

If the Minimum Participation Condition is met, and if certain customary closing conditions are satisfied (including approval by each company’s shareholders, provided that approval of ~~accounting.~~ HighPoint shareholders will not be required under the Prepackaged Plan), the companies will effect the Exchange Offer and Bonanza Creek will acquire HighPoint at closing through a merger outside of bankruptcy.

The ~~financial information may not necessarily be indicative~~transactions are expected to close in the first quarter of ~~results~~2021 under the Exchange Offer or in the second quarter of ~~operations, cash flows, or financial position had~~2021 under the ~~subsidiaries operated as independent entities.~~

~~Condensed Consolidating Balance Sheets~~

Prepackaged Plan.

As of March 31, 2018
Parent
Guarantor Subsidiary
Issuer Subsidiary
Guarantor Intercompany
Eliminations Consolidated
(in thousands)
Assets:
Cash and cash equivalents $ —
$ 224,692
$ —
$ —
$ 224,692
Accounts receivable, net of allowance for doubtful accounts —
50,268
—
—
50,268
Other current assets —
2,393
—
—
2,393
Property and equipment, net —
1,809,548
1,894
—
1,811,442
Intercompany receivable —
854
—
(854 ) —
Investment in subsidiaries 1,060,340
1,040
—
(1,061,380 ) —
Noncurrent assets —
3,679
—
—
3,679
Total assets $ 1,060,340
$ 2,092,474
$ 1,894
$ (1,062,234 ) $ 2,092,474
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities $ —
$ 135,925
$ —
$ —
$ 135,925
Other current liabilities —
104,463
—
—
104,463
Intercompany payable —
—
854
(854 ) —
Long-term debt —
616,244
—
—
616,244
Deferred income taxes —
137,111
—
—
137,111
Other noncurrent liabilities —
38,391
—
—
38,391
Stockholders' equity 1,060,340
1,060,340
1,040
(1,061,380 ) 1,060,340
Total liabilities and stockholders' equity $ 1,060,340
$ 2,092,474
$ 1,894
$ (1,062,234 ) $ 2,092,474

Table of Contents

As of December 31, 2017
Parent
Issuer Subsidiary
Guarantors Intercompany
Eliminations Consolidated
(in thousands)
Assets:
Cash and cash equivalents $ 314,466
$ —
$ —
$ 314,466
Accounts receivable, net of allowance for doubtful accounts 51,415
—
—
51,415
Other current assets 1,782
—
—
1,782
Property and equipment, net 1,016,986
1,894
—
1,018,880
Intercompany receivable 854
—
(854 ) —
Investment in subsidiaries 1,040
—
(1,040 ) —
Noncurrent assets 4,163
—
—
4,163
Total assets $ 1,390,706
$ 1,894
$ (1,894 ) $ 1,390,706
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities $ 84,055
$ —
$ —
$ 84,055
Other current liabilities 64,879
—
—
64,879
Intercompany payable —
854
(854 ) —
Long-term debt 617,744
—
—
617,744
Other noncurrent liabilities 25,474
—
—
25,474
Stockholders' equity 598,554
1,040
(1,040 ) 598,554
Total liabilities and stockholders' equity $ 1,390,706
$ 1,894
$ (1,894 ) $ 1,390,706

~~Condensed Consolidating Statements of Operations~~

Three Months Ended March 31, 2018
Parent
Guarantor Subsidiary
Issuer Subsidiary
Guarantor Intercompany
Eliminations Consolidated
(in thousands)
Operating and other revenues $ —
$ 80,810
$ —
$ —
$ 80,810
Operating expenses —
(58,145 ) —
—
(58,145 )
General and administrative —
(10,107 ) —
—
(10,107 )
Merger transaction expense —
(4,763 ) —
—
(4,763 )
Interest expense —
(13,090 ) —
—
(13,090 )
Interest income and other income (expense) —
(19,642 ) —
—
(19,642 )
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries —
(24,937 ) —
—
(24,937 )
(Provision for) benefit from income taxes —
—
—
—
—
Equity in earnings (loss) of subsidiaries (24,937 ) —
—
24,937
—
Net income (loss) $ (24,937 ) $ (24,937 ) $ —
$ 24,937
$ (24,937 )

Three Months Ended March 31, 2017
Parent
Issuer Subsidiary
Guarantors Intercompany Eliminations Consolidated
(in thousands)
Operating and other revenues $ 50,425
$ 111
$ —
$ 50,536
Operating expenses (56,858 ) (163 ) —
(57,021 )
General and administrative (9,349 ) —
—
(9,349 )
Interest expense (13,951 ) —
—
(13,951 )
Interest income and other income (expense) 16,670
—
—
16,670
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries (13,063 ) (52 ) —
(13,115 )
(Provision for) benefit from income taxes —
—
—
—
Equity in earnings (loss) of subsidiaries (52 ) —
52
—
Net income (loss) $ (13,115 ) $ (52 ) $ 52
$ (13,115 )

~~Condensed Consolidating Statements of Comprehensive Income (Loss)~~

Three Months Ended March 31, 2018
Parent
Guarantor Subsidiary
Issuer Subsidiary
Guarantor Intercompany
Eliminations Consolidated
(in thousands)
Net income (loss) $ (24,937 ) $ (24,937 ) $ —
$ 24,937
$ (24,937 )
Other comprehensive loss —
—
—
—
—
Comprehensive income (loss) $ (24,937 ) $ (24,937 ) $ —
$ 24,937
$ (24,937 )

Three Months Ended March 31, 2017
Parent
Issuer Subsidiary
Guarantors Intercompany
Eliminations Consolidated
(in thousands)
Net income (loss) $ (13,115 ) $ (52 ) $ 52
$ (13,115 )
Other comprehensive loss —
—
—
—
Comprehensive income (loss) $ (13,115 ) $ (52 ) $ 52
$ (13,115 )

~~Condensed Consolidating Statements of Cash Flows~~

Three Months Ended March 31, 2018
Parent
Guarantor Subsidiary
Issuer Subsidiary
Guarantor Intercompany
Eliminations Consolidated
(in thousands)
Cash flows from operating activities $ —
$ 54,317
$ —
$ —
$ 54,317
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions —
(88,854 ) —
—
(88,854 )
Additions to furniture, fixtures and other —
(122 ) —
—
(122 )
Repayment of debt associated with merger, net of cash acquired —
(53,357 ) —
—
(53,357 )
Proceeds from sale of properties and other investing activities —
(157 ) —
—
(157 )
Intercompany transfers —
—
—
—
—
Cash flows from financing activities:
Principal payments on debt —
(116 ) —
—
(116 )
Intercompany transfers —
—
—
—
—
Other financing activities —
(1,485 ) —
—
(1,485 )
Change in cash and cash equivalents —
(89,774 ) —
—
(89,774 )
Beginning cash and cash equivalents —
314,466
—
—
314,466
Ending cash and cash equivalents $ —
$ 224,692
$ —
$ —
$ 224,692

Three Months Ended March 31, 2017
Parent
Issuer Subsidiary
Guarantors Intercompany
Eliminations Consolidated
(in thousands)
Cash flows from operating activities $ 37,930
$ 168
$ —
$ 38,098
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions (57,963 ) —
—
(57,963 )
Additions to furniture, fixtures and other (11 ) —
—
(11 )
Proceeds from sale of properties and other investing activities 11,225
—
—
11,225
Intercompany transfers 168
—
(168 ) —
Cash flows from financing activities:
Principal payments on debt (112 ) —
—
(112 )
Proceeds from sale of common stock, net of offering costs (224 ) —
—
(224 )
Intercompany transfers —
(168 ) 168
—
Other financing activities (967 ) —
—
(967 )
Change in cash and cash equivalents (9,954 ) —
—
(9,954 )
Beginning cash and cash equivalents 275,841
—
—
275,841
Ending cash and cash equivalents $ 265,887
$ —
$ —
$ 265,887

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

This Quarterly Report on Form 10-Q contains ~~"forward-looking statements"~~“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:

~~potential~~•any failure to ~~achieve expected production from existing and future exploration~~comply with the financial or ~~development projects or acquisitions;~~

~~volatility of market prices received for oil, natural gas and natural gas liquids ("NGLs"~~other covenants under our revolving credit facility (the “Credit Facility”), and the ~~risk of~~related impact on our ability to continue as a ~~prolonged period of depressed prices;~~going concern;

~~declines~~•reductions in the ~~values~~borrowing base under our Credit Facility, and the related impact on our ability to continue as a going concern;

•debt and equity market conditions and availability of capital, and the related impact on our ability to continue as a going concern;

•ability to regain compliance with the average market capitalization and stockholders’ equity requirement under the New York Stock Exchange (the “NYSE”) continued listing requirements and avert the delisting of our common stock;

•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 ~~natural gas properties resulting in impairments;~~production controls;

~~reduction of proved undeveloped reserves~~•downstream shut-ins due to ~~failure to develop within the five-year development window defined by the Securities~~oversupply and ~~Exchange Commission;~~shortage of storage capacity;

~~derivative and hedging activities;~~

•legislative, judicial or regulatory changes including initiatives to impose ~~standard~~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;

~~solely operating~~•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;

•inability to hedge production at favorable prices;

•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;

~~reductions in the borrowing base under our amended revolving credit facility (the "Amended Credit Facility");~~

~~debt and equity market conditions and availability of capital;~~

•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 ~~copacity~~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, ~~2017~~2019 under the headings ~~"Cautionary~~“Cautionary Note Regarding Forward-Looking ~~Statements"~~Statements” and ~~"Risk Factors"~~“Risk

Table of Contents

Factors” and in Part II, Item 1A, ~~"Risk Factors"~~“Risk Factors” of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

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~~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 became the successor to Bill Barrett Corporation ("Bill Barrett") on March 19, 2018 upon completion of the business combination (the "Merger") between Bill Barrett and Fifth Creek Operating Company, LLC ("Fifth Creek"). Except where the context indicates otherwise, the terms "we", "us", "our" or the "Company" as used herein refer, for periods prior to the

completion of the Merger, to Bill Barrett and its subsidiaries and, for periods following the completion of the Merger, to HighPoint Resources Corporation and its subsidiaries (including Bill Barrett, which has subsequently been renamed HighPoint Operating Corporation).

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'~~stakeholders’ expectations and regulatory requirements.

~~Future acquisitions or dispositions could~~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. Crude prices averaged $40.93 per barrel for three months ended September 30, 2020. These declines in prices have ~~a material impact on~~adversely affected the economics of our ~~financial condition~~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 nine months ended September 30, 2020 from price declines were mitigated by ~~increasing or decreasing our reserves, production~~hedges in place on 96% and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, and/or the issuance of debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale89%, respectively, of our ~~equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.~~

As a result of acquisitions and dispositions of properties, our historical results of operations and period-to-period comparisons of these results and certain financial data may not be meaningful. In addition, past results are not necessarily indicative of future results.

~~Commodity prices are inherently volatile and are influenced by many factors outside of our control.~~oil production. As of ~~April 24, 2018,~~October 30, 2020, we have hedged ~~3,602,619~~1,150,000 barrels ~~of oil and 1,375,000 MMbtu of natural gas, or approximately 43%~~ of our expected remaining ~~2018~~2020 oil production ~~4,557,934~~and 3,098,000 barrels of our expected 2021 oil ~~for 2019 and 183,000 barrels of oil for 2019~~production, at price levels that provide some economic certainty to our cash flows. ~~We focus~~In addition, we have hedged 2,760,000 MMbtu of our ~~efforts on increasing oil,~~expected remaining 2020 natural gas production, and ~~NGLs reserves~~7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, ~~while controlling costs~~respectively. 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 of 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.

We have financial covenants associated with our 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, as discussed in the “Going Concern” section in Note 2, based on our financial projections for the twelve month period following the issuance date of these interim consolidated financial statements, it is probable we will breach a ~~level that is appropriate for long-term operations. Our future earnings~~financial covenant in our Credit Facility in the second quarter of 2021. If this breach were to occur and ~~cash flows are dependent on~~we do not receive a waiver from the lenders, all of the amount borrowed under the Credit Facility will become due, and cross-defaults will occur under the indentures to our senior notes. Further, if our independent auditor includes an explanatory paragraph regarding our ability to ~~manage~~continue as a “going concern” in its report on our ~~revenues~~financial statements for the year ending December 31, 2020, this would accelerate a default under

Table of Contents

our Credit Facility to the first quarter of 2021 at the time our financial statements for the year ending December 31, 2020 are filed and, ~~overall cost structure~~in turn, result in cross-default under the indentures to the senior notes at that time as well. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a ~~level~~going concern.

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.

On October 20, 2020, we announced a reverse stock split of our outstanding shares of common stock at a ratio of 1-for-50 and a proportionate reduction of the total number of authorized shares of common stock, which was approved by the stockholders at our Annual Meeting of Stockholders on April 28, 2020. The reverse stock split became effective on October 30, 2020, and our common stock was traded on a split-adjusted basis on the NYSE at the market open on that ~~allows~~date. The par value of the common stock was not adjusted as a result of the reverse stock split.

The reverse stock split is intended to increase the per share trading price of our common stock to satisfy the $1.00 minimum closing price requirement for ~~profitable production.~~continued listing on the NYSE. As a result of the reverse stock split, every 50 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled and paid out in cash. The reverse stock split reduced the number of shares of our outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares, subject to adjustment of the rounding of fractional shares. The total number of shares of common stock that we are authorized to issue was reduced from 400,000,000 to 8,000,000 shares. All share and per share amounts were retroactively adjusted in the consolidated financial statements and notes herein for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of our common stock to additional paid-in capital.

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.

~~As a result~~

Table of the closing of the Merger on March 19, 2018, Fifth Creek's assets and liabilities are included in the Unaudited Consolidated Balance Sheet as of March 31, 2018 and Fifth Creek's revenues and expenses are included in the Unaudited Consolidated StatementContents

Results of Operations

The following table sets forth selected operating data for the ~~period from March 19, 2018 to March 31, 2018. See Note 4 for additional information regarding the accounting for the Merger.~~periods indicated:

Three Months Ended ~~March 31, 2018~~September 30, 2020 Compared with Three Months Ended ~~March 31, 2017~~September 30, 2019


	Three Months Ended September 30,				Increase (Decrease)
	2020		2019		Amount		Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	67,305	$	121,281	$	(53,976)	(45)	%
Other operating revenues	42		1		41		4,100	%
Total operating revenues	67,347		121,282		(53,935)		(44)	%
Operating Expenses
Lease operating expense	5,305		8,385		(3,080)		(37)	%
Gathering, transportation and processing expense	5,317		1,611		3,706		230	%
Production tax expense	(1,074)		7,868		(8,942)		*nm
Exploration expense	74		56		18		32	%
Impairment and abandonment expense	2,813		1,170		1,643		140	%
(Gain) loss on sale of properties	18		—		18		*nm
Depreciation, depletion and amortization	25,522		84,948		(59,426)		(70)	%
Unused commitments	4,985		4,418		567		13	%
General and administrative expense (1)	12,891		11,048		1,843		17	%
Merger transaction expense	—		2,078		(2,078)		(100)	%
Other operating expense, net	(38)		230		(268)		*nm
Total operating expenses	$	55,813	$	121,812	$	(65,999)	(54)	%
Production Data:
Oil (MBbls)	1,507		2,180		(673)		(31)	%
Natural gas (MMcf)	4,254		4,236		18		—	%
NGLs (MBbls)	628		513		115		22	%
Combined volumes (MBoe)	2,844		3,399		(555)		(16)	%
Daily combined volumes (Boe/d)	30,913		36,946		(6,033)		(16)	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	36.64	$	52.27	$	(15.63)	(30)	%
Natural gas (per Mcf)	1.36		1.03		0.33		32	%
NGLs (per Bbl)	10.04		5.76		4.28		74	%
Combined (per Boe)	23.66		35.68		(12.02)		(34)	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	51.84	$	54.08	$	(2.24)	(4)	%
Natural gas (per Mcf)	1.39		1.06		0.33		31	%
NGLs (per Bbl)	10.04		5.76		4.28		74	%
Combined (per Boe)	31.77		36.88		(5.11)		(14)	%
Average Costs (per Boe):
Lease operating expense	$	1.87	$	2.47	$	(0.60)	(24)	%
Gathering, transportation and processing expense	1.87		0.47		1.40		298	%
Production tax expense	(0.38)		2.31		(2.69)		*nm
Depreciation, depletion and amortization	8.97		24.99		(16.02)		(64)	%
General and administrative expense (1)	4.53		3.25		1.28		39	%

*Not meaningful.

Table of Contents

Three Months Ended March 31, Increase (Decrease)
2018 2017 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production $ 80,831
$ 50,425
$ 30,406
60 %
Other operating revenues (21 ) 111
(132 ) (119 )%
Total operating revenues 80,810
50,536
30,274
60 %
Operating Expenses
Lease operating expense 6,251
5,862
389
7 %
Gathering, transportation and processing expense 419
489
(70 ) (14 )%
Production tax expense 5,175
322
4,853
*nm
Exploration expense 13
27
(14 ) (52 )%
Impairment, dry hole costs and abandonment expense 317
8,074
(7,757 ) (96 )%
(Gain) loss on sale of properties 408
(92 ) 500
543 %
Depreciation, depletion and amortization 40,985
38,340
2,645
7 %
Unused commitments 4,538
4,572
(34 ) (1 )%
General and administrative expense ⁽¹⁾
10,107
9,349
758
8 %
Merger transaction expense 4,763
—
4,763
*nm
Other operating expenses, net 39
(573 ) 612
107 %
Total operating expenses $ 73,015
$ 66,370
$ 6,645
10 %
Production Data:
Oil (MBbls) 1,137
825
312
38 %
Natural gas (MMcf) 2,562
1,890
672
36 %
NGLs (MBbls) 350
293
57
19 %
Combined volumes (MBoe) 1,914
1,433
481
34 %
Daily combined volumes (Boe/d) 21,267
15,922
5,345
34 %
Average Realized Prices Before Hedging:
Oil (per Bbl) $ 60.45
$ 47.92
$ 12.53
26 %
Natural gas (per Mcf) 1.95
2.66
(0.71 ) (27 )%
NGLs (per Bbl) 20.31
20.04
0.27
1 %
Combined (per Boe) 42.24
35.18
7.06
20 %
Average Realized Prices with Hedging:
Oil (per Bbl) $ 53.00
$ 52.41
$ 0.59
1 %
Natural gas (per Mcf) 1.98
2.62
(0.64 ) (24 )%
NGLs (per Bbl) 20.31
20.04
0.27
1 %
Combined (per Boe) 37.86
37.71
0.15
— %
Average Costs (per Boe):
Lease operating expense $ 3.27
$ 4.09
$ (0.82 ) (20 )%
Gathering, transportation and processing expense 0.22
0.34
(0.12 ) (35 )%
Production tax expense 2.70
0.22
2.48
*nm
Depreciation, depletion and amortization 21.41
26.76
(5.35 ) (20 )%
General and administrative expense ⁽¹⁾
5.28
6.52
(1.24 ) (19 )%
(1)Included in general and administrative expense is long-term cash and equity incentive compensation of $1.0 million (or $0.34 per Boe) and $2.1 million (or $0.63 per Boe) for the three months ended September 30, 2020 and 2019, respectively.


*	~~Not meaningful.~~


~~(1)~~	Included in general and administrative expense is long-term cash and equity incentive compensation of $1.4 million (or $0.75 per Boe) and $1.1 million (or $0.79 per Boe) for the three months ended March 31, 2018 and 2017, respectively.

Production Revenues and Volumes. Production revenues ~~increased~~decreased to ~~$80.8~~$67.3 million for the three months ended ~~March 31, 2018~~September 30, 2020 from ~~$50.4~~$121.3 million for the three months ended ~~March 31, 2017.~~September 30, 2019. The ~~increase~~decrease in production revenues was due to a ~~20% increase~~34% decrease in average realized prices before hedging and a ~~34% increase~~16% decrease in production volumes. The ~~increase~~decrease in average realized prices before hedging ~~increased~~decreased production revenues by approximately ~~$10.1~~$40.9 million, while the ~~increase~~decrease in production volumes ~~increased~~decreased production revenues by approximately ~~$20.3~~$13.1 million. Without further development, we anticipate a decline in production for the remainder of the year.

~~The 34% increase in total production from~~

Lease Operating Expense (“LOE”). LOE was $5.3 million for the three months ended ~~March 31, 2017 to~~September 30, 2020 and $8.4 million for the three months ended March 31, 2018 was primarily due to a 50% increase in the DJ Basin as a result of new wells placed into production, along with new wells acquired in the Merger, offset by the sale of our remaining assets in the Uinta Oil Program in December 2017. Additional information concerning production is set forth in the following table:

Three Months Ended March 31, 2018 Three Months Ended March 31, 2017 % Increase (Decrease)
Oil NGL Natural
Gas Total Oil NGL Natural
Gas Total Oil NGL Natural
Gas Total
(MBbls) (MBbls) (MMcf) (MBoe) (MBbls) (MBbls) (MMcf) (MBoe) (MBbls) (MBbls) (MMcf) (MBoe)
DJ Basin 1,137
350
2,562
1,914
679
291
1,842
1,277
67 % 20 % 39 % 50 %
Other ⁽¹⁾
—
—
—
—
146
2
48
156
*nm
*nm
*nm
*nm
Total 1,137
350
2,562
1,914
825
293
1,890
1,433
38 % 19 % 36 % 34 %


*	~~Not meaningful.~~


~~(1)~~	~~Other includes 145 MBbls of oil, 1 MBbls of NGLs and 48 MMcf of natural gas production in the Uinta Oil Program for the three months ended March 31, 2017.~~

~~Lease Operating Expense ("LOE")~~.September 30, 2019. LOE decreased to ~~$3.27~~$1.87 per Boe for the three months ended ~~March 31, 2018~~September 30, 2020 from ~~$4.09~~$2.47 per Boe for the three months ended ~~March 31, 2017. The~~September 30, 2019. We continued to see a decrease in service industry costs during the three months ended September 30, 2020 due to a downturn in the industry. We anticipate an increase in LOE for the remainder of the year due to colder temperatures and potential adverse weather in the winter months.

Gathering, Transportation and Processing Expense (“GTP”). GTP expense increased to $1.87 per Boe for the three months ended ~~March 31, 2018 compared with~~September 30, 2020 from $0.47 per Boe for the three months ended ~~March 31, 2017 is primarily related~~September 30, 2019.

Costs incurred to ~~operational efficiencies~~gather, transport and/or process our oil, gas and ~~sale~~NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our ~~remaining assets~~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 ~~Uinta Oil Program~~Hereford Field in the DJ Basin, which was acquired in the 2018 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 September 30, 2020 compared to the three months ended September 30, 2019 was primarily due to an increase in our Hereford Field based on minimum volume commitments under the existing contractual arrangement, which expires in December ~~2017, which had relatively high LOE costs on a per Boe basis.~~2021.

Production Tax Expense. Total production taxes ~~increased~~decreased to ~~$5.2~~a negative $1.1 million for the three months ended ~~March 31, 2018~~September 30, 2020 from ~~$0.3~~$7.9 million for the three months ended ~~March 31, 2017. Production tax expense for both periods included an annual true-up of Colorado ad valorem tax based on actual assessments and a true-up of the Colorado severance tax.~~September 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 the three months ended September 30, 2020 included a reduction of $5.4 million to our estimated 2019 Colorado ad valorem tax that is due in 2021. Excluding the ~~ad valorem and severance tax adjustments,~~adjustment for the three months ended September 30, 2020, production taxes as a percentage of oil, natural gas and NGL sales were ~~8.9%~~6.4% and ~~6.7%~~6.5% for the three months ended ~~March 31, 2018~~September 30, 2020 and ~~2017,~~September 30, 2019, respectively. ~~The increase was due to an increase in the effective rate of Colorado severance taxes for the three months ended March 31, 2018.~~

Impairment ~~Dry Hole Costs~~ and Abandonment Expense. ~~Our impairment, dry hole costs and abandonment expense for the three months ended March 31, 2018 and 2017 are summarized below:~~

Three Months Ended March 31,
2018 2017
(in thousands)
Impairment of unproved oil and gas properties ⁽¹⁾
$ —
$ 8,010
Dry hole expense —
2
Abandonment expense and lease expirations 317
62
Total impairment, dry hole costs and abandonment expense $ 317
$ 8,074


~~(1)~~	~~The Company recognized an impairment related to unproved oil and gas properties in the Cottonwood Gulch area of the Piceance Basin. The Company has no current plan to develop this acreage.~~

We review our 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~~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. We do not believe that the undiscounted future net cash flows of our oil and gas properties represent the applicable market 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 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 on a property-by-property basis 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.

As a result of our continuous review of our acreage position and future drilling plans, we recognized $2.5 million of non-cash impairment associated with unproved oil and gas properties during the three months ended September 30, 2020 associated with certain leases that will expire subsequent to the balance sheet date that we do not plan to renew. Our impairment, dry hole costs and abandonment expense for the three months ended September 30, 2020 and 2019 is summarized below:


	Three Months Ended September 30,
	2020		2019
	(in thousands)

Impairment of unproved oil and gas properties	$	2,537	$	—

Abandonment expense	276		1,170
Total impairment, dry hole costs and abandonment expense	$	2,813	$	1,170

Given current and projected future commodity prices, we will continue to review our acreage position and future drilling plans. In addition, we will assess the carrying value of our properties relative to their estimated future net cash flows. Estimated future net cash flows from our properties are based on our aggregate best estimates of future production, commodity pricing, gathering and transportation deducts, production tax rates, lease operating expenses and future development costs as of the balance sheet date.

Depreciation, Depletion and Amortization ("(“DD~~&A"~~&A”). DD&A ~~increased~~decreased to ~~$41.0~~$25.5 million for the three months ended ~~March 31, 2018~~September 30, 2020 compared with ~~$38.3~~$84.9 million for the three months ended ~~March 31, 2017.~~September 30, 2019. The ~~increase~~decrease of ~~$2.6~~$59.4 million was a result of a ~~20%~~16% decrease in production volumes and a 64% decrease in the DD&A rate ~~offset by a 34% increase in production~~ for the three months ended ~~March 31, 2018~~September 30, 2020 compared with the three months ended ~~March 31, 2017.~~September 30, 2019. The decrease in production accounted for a $13.9 million decrease in DD&A expense, while the decrease in the DD&A rate accounted for a ~~$10.2~~$45.5 million decrease in DD&A ~~expense, while the increase in production accounted for a $12.8 million increase in DD&A~~ expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis ~~within a common geological structure~~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 ~~March 31, 2018,~~September 30, 2020, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of ~~$21.41~~$8.97 per Boe compared with ~~$26.76~~$24.99 per Boe for the three months ended ~~March 31, 2017.~~September 30, 2019. The decrease in the depletion rate of ~~20% is the~~64% was a result of ~~adding~~recognizing a $1.2 billion impairment associated with our proved ~~developed producing reserves at lower costs.~~oil and gas properties during the three months ended March 31, 2020.

Unused Commitments. Unused commitments expense was $5.0 million and $4.4 million for the three months ended September 30, 2020 and September 30, 2019, respectively, primarily 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 (“G&A”). G&A expense increased to $12.9 million for the three months ended September 30, 2020 from $11.0 million for the three months ended September 30, 2019. G&A expense on a Boe basis increased to $4.53 for the three months ended September 30, 2020 from $3.25 for the three months ended September 30, 2019. The increase in G&A expense for the three months ended September 30, 2020 was a result of incurring legal and advisory fees for advisors to assist with a potential comprehensive restructuring of our indebtedness and an evaluation of a range of strategic alternatives, which resulted in the Merger Agreement discussed in Note 12. In addition to continued higher legal and advisory fees, we anticipate an increase in G&A for the remainder of the year due to officer compensation agreements, which were revised in October 2020.

Included in general and administrative expense is long-term cash and equity incentive compensation of $1.0 million and $2.1 million for the three months ended September 30, 2020 and 2019, respectively. The decrease for the three months ended September 30, 2020 was due to a reduction in overall equity awards granted during the three months ended September 30, 2020. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2020 and 2019 are shown in the following table:

Table of Contents


	Three Months Ended September 30,
	2020		2019
	(in thousands)
Nonvested common stock	$	996	$	1,992
Nonvested common stock units	30		283
Nonvested performance cash units (1)	(55)		(130)
Total	$	971	$	2,145

(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.

Merger Transaction Expense. Merger transaction expense was $2.1 million for the three months ended September 30, 2019. Transaction expenses included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the 2018 Merger.

Interest Expense. Interest expense decreased to $14.3 million for the three months ended September 30, 2020 from $15.2 million for the three months ended September 30, 2019. The decrease for the three months ended September 30, 2020 was due to decreased borrowings under the Credit Facility during the three months ended September 30, 2020. See Note 4 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative loss was $13.7 million for the three months ended September 30, 2020 compared with a gain of $31.0 million for the three months ended September 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 September 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 September 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 September 30,
	2020		2019
	(in thousands)
Realized gain (loss) on derivatives (1)	$	23,059	$	4,075
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	691		(20,739)
Unrealized gain (loss) on derivatives (1)	(37,496)		47,711
Total commodity derivative gain (loss)	$	(13,746)	$	31,047

(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 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.

Table of Contents

During the three months ended September 30, 2020, approximately 96% of our oil volumes and 41% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $22.9 million and natural gas income of $0.2 million after settlements. During the three months ended September 30, 2019, approximately 83% of our oil volumes and 15% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $4.0 million and an increase in natural gas income of $0.1 million after settlements.

The COVID-19 pandemic caused a severe decline in current and estimated future oil and gas prices during the three months ended September 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 September 30, 2020 and 2019, income tax expense of $0.6 million and $0.1 million were recognized, respectively. During the three months ended March 31, ~~2018~~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. During the three months ended September 30, 2020 additional analysis of the scheduled reversal of deferred tax assets and liabilities resulted in recognizing a benefit of $0.6 million. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets.

Table of Contents

Nine Months Ended September 30, 2020 Compared with Nine Months Ended September 30, 2019


	Nine Months Ended September 30,				Increase (Decrease)
	2020		2019		Amount		Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	190,171	$	330,472	$	(140,301)	(42)	%
Other operating revenues	42		374		(332)		(89)	%
Total operating revenues	190,213		330,846		(140,633)		(43)	%
Operating Expenses
Lease operating expense	25,460		30,434		(4,974)		(16)	%
Gathering, transportation and processing expense	13,983		5,076		8,907		175	%
Production tax expense	(2,133)		20,666		(22,799)		*nm
Exploration expense	126		93		33		35	%
Impairment and abandonment expense	1,269,049		2,487		1,266,562		*nm
(Gain) loss on sale of properties	4,797		2,901		1,896		65	%
Depreciation, depletion and amortization	125,355		230,170		(104,815)		(46)	%
Unused commitment	13,821		13,239		582		4	%
General and administrative expense (1)	35,996		36,109		(113)		—	%
Merger transaction expense	—		4,492		(4,492)		(100)	%
Other operating expense, net	(540)		210		(750)		*nm
Total operating expenses	$	1,485,914	$	345,877	$	1,140,037	330	%
Production Data:
Oil (MBbls)	4,731		5,648		(917)		(16)	%
Natural gas (MMcf)	12,564		11,544		1,020		9	%
NGLs (MBbls)	1,798		1,466		332		23	%
Combined volumes (MBoe)	8,623		9,038		(415)		(5)	%
Daily combined volumes (Boe/d)	31,471		33,106		(1,635)		(5)	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	33.86	$	52.82	$	(18.96)	(36)	%
Natural gas (per Mcf)	1.16		1.58		(0.42)		(27)	%
NGLs (per Bbl)	8.55		9.47		(0.92)		(10)	%
Combined (per Boe)	22.05		36.57		(14.52)		(40)	%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	53.31	$	54.31	$	(1.00)	(2)	%
Natural gas (per Mcf)	1.20		1.52		(0.32)		(21)	%
NGLs (per Bbl)	8.55		9.47		(0.92)		(10)	%
Combined (per Boe)	32.78		37.42		(4.64)		(12)	%
Average Costs (per Boe):
Lease operating expense	$	2.95	$	3.37	$	(0.42)	(12)	%
Gathering, transportation and processing expense	1.62		0.56		1.06		189	%
Production tax expense	(0.25)		2.29		(2.54)		*nm
Depreciation, depletion and amortization	14.54		25.47		(10.93)		(43)	%
General and administrative expense (1)	4.17		4.00		0.17		4	%

*Not meaningful.

(1)Included in general and administrative expense is long-term cash and equity incentive compensation of $3.0 million (or $0.35 per Boe) and $7.2 million (or $0.79 per Boe) for the nine months ended September 30, 2020 and 2019, respectively.

Table of Contents

Production Revenues and Volumes. Production revenues decreased to $190.2 million for the nine months ended September 30, 2020 from $330.5 million for the nine months ended September 30, 2019. The decrease in production revenues was due to a 40% decrease in average realized prices before hedging and a 5% decrease in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $131.1 million, while the decrease in production volumes decreased production revenues by approximately $9.2 million. Without further development, we anticipate a decline in production for the remainder of the year.

Lease Operating Expense. LOE was $25.5 million for the nine months ended September 30, 2020 and $30.4 million for the nine months ended September 30, 2019. LOE decreased to $2.95 per Boe for the nine months ended September 30, 2020 from $3.37 per Boe for the nine months ended September 30, 2019. We started seeing a decrease in service industry costs during the nine months ended September 30, 2020 due to a downturn in the industry. We anticipate an increase in LOE for the remainder of the year due to colder temperatures and potential adverse weather in the winter months.

Gathering, Transportation and Processing Expense. GTP expense increased to $1.62 per Boe for the nine months ended September 30, 2020 from $0.56 per Boe for the nine months ended September 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 nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 was primarily due to an increase from the Hereford Field based on minimum volume commitments under the existing contractual arrangement, which expires in December 2021.

Production Tax Expense. Total production taxes decreased to negative $2.1 million for the nine months ended September 30, 2020 from $20.7 million for the nine months ended September 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 nine months ended September 30, 2020 also included a reduction of $5.4 million to our estimated 2019 Colorado ad valorem tax that is due in 2021 and 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, ~~consisted~~production taxes as a percentage of ~~$4.5~~oil, natural gas and NGL sales were 6.5% and 7.7% for the nine months ended September 30, 2020 and 2019, respectively. The decrease in the rate for the nine months ended September 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 nine months ended September 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 of $1.2 billion associated with proved oil and gas properties and $76.3 million associated with unproved oil and gas properties. In addition, we recognized non-cash impairment associated with unproved oil and gas properties of $2.5 million associated with certain leases that will expire subsequent to the balance sheet date that we do not plan to renew as the result of our continuous review of our acreage position and future drilling plans. Our impairment and abandonment expense for the nine months ended September 30, 2020 and 2019 is summarized below:


	Nine Months Ended September 30,
	2020		2019

Impairment of proved oil and gas properties	$	1,188,566	$	—
Impairment of unproved oil and gas properties	78,835		—


Abandonment expense	1,648		2,487
Total impairment and abandonment expense	$	1,269,049	$	2,487

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 $125.4 million for the nine months ended September 30, 2020 compared with $230.2 million for the nine months ended September 30, 2019. The decrease of $104.8 million was a result of a 5% decrease in production and a 43% decrease in the DD&A rate for the nine months ended September 30, 2020 compared with the nine months ended September 30, 2019. The decrease in production accounted for a $10.6 million decrease in DD&A expense while the decrease in the DD&A rate accounted for a $94.2 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 nine months ended September 30, 2020, the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $14.54 per Boe compared with $25.47 per Boe for the nine months ended September 30, 2019. The decrease in the depletion rate of 43% was a result of recognizing a $1.2 billion impairment associated with our proved oil and gas properties during the nine months ended September 30, 2020.

Unused Commitments. Unused commitments expense was $13.8 million and ~~$4.6~~$13.2 million for the three and nine months ended September 30, 2020 and September 30, 2019, respectively, primarily 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 ~~increased~~decreased to ~~$10.1~~$36.0 million for the ~~three~~nine months ended ~~March 31, 2018~~September 30, 2020 from ~~$9.3~~$36.1 million for the ~~three~~nine months ended ~~March 31, 2017 primarily~~September 30, 2019. General and administrative expense on a Boe basis increased to $4.17 for the nine months ended September 30, 2020 from $4.00 for the nine months ended September 30, 2019. The decrease in general and administrative expense for the nine months ended September 30, 2020 was due to ~~an increase~~a decrease in long-term cash and equity incentive compensation discussed below, ~~as well as~~offset by an increase in ~~employee~~legal and advisory fees incurred for advisors to assist with a potential comprehensive restructuring of our indebtedness and an evaluation of a range of strategic alternatives, which resulted in the Merger Agreement discussed in Note 12. In addition to continued higher legal and advisory fees, we anticipate an increase in G&A for the remainder of the year due to officer compensation ~~and benefits.~~agreements, which were revised in October 2020.

Included in general and administrative expense is long-term cash and equity incentive compensation of ~~$1.4~~$3.0 million and ~~$1.1~~$7.2 million for the ~~three~~nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017,~~2019, respectively. The decrease for the nine months ended September 30, 2020 was due to a reduction in overall equity awards granted during the nine months ended September 30, 2020.

Table of Contents

The components of long-term cash and equity incentive compensation for the ~~three~~nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017~~2019 are shown in the following table:


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Nonvested common stock	$	3,296	$	5,321
Nonvested common stock units	512		895
Nonvested performance cash units (1)	(831)		947
Total	$	2,977	$	7,163

Three Months Ended March 31,
2018 2017
(in thousands)
Nonvested common stock $ 1,330
$ 1,919
Nonvested common stock units 170
170
Performance cash units ⁽¹⁾⁽²⁾
(73 ) (961 )
Total $ 1,427
$ 1,128


~~(1)~~	~~The performance cash units will be settled in cash for the performance metrics that are met.~~

~~(2)~~

The performance cash units are accounted for as liability awards and fair valued at each reporting date. For the three months ended March 31, 2018, the weighted average fair value share price decreased from $5.10 as of December 31, 2017 to $5.08 as of March 31, 2018. Prior to the 2016 and 2017 Program conversion that occurred in connection with the Merger, the weighted average fair value share price was $4.63, resulting in a decrease in expense offset by an increase in expense for the 2018 Program. For the three months ended March 31, 2017, the weighted average fair value share price decreased from $8.89 as of December 31, 2016 to $4.55 as of March 31, 2017. See Note 11 for additional information on the liability to equity award conversion of the 2016 and 2017 Programs.

Merger Transaction Expense. Merger transaction expense ~~was $4.8~~of $4.5 million for the ~~three~~nine months ended ~~March 31, 2018. We entered into the Merger Agreement on December 4, 2017 and closed on March 19, 2018. Transaction expenses~~September 30, 2019 included severance, consulting, advisory, legal and other merger-related fees that were ~~incurred during the three months ended March 31, 2018 and will~~ not be capitalized as part of the 2018 Merger. ~~We previously expensed $8.7~~

Interest Expense. Interest expense increased to $44.1 million for the nine months ended September 30, 2020 from $43.2 million for the nine months ended September 30, 2019. The increase for the nine months ended September 30, 2020 was due to accelerating the expense of $1.0 million of ~~merger transaction expenses incurred~~deferred financing costs associated with the amendment of our Credit Facility in ~~the fourth quarter of 2017.~~May 2020. See Note 4 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative gain ~~(loss)~~ was $144.6 million for the nine months ended September 30, 2020 compared with a loss of ~~$20.3~~$54.6 million for the ~~three~~nine months ended ~~March 31, 2018 compared with a~~September 30, 2019. The gain ~~of $16.5 million~~ for the ~~three~~nine months ended ~~March 31, 2017. The~~September 30, 2020 compared to the loss for the ~~three~~nine months ended ~~March 31, 2018 is~~September 30, 2019 was related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of ~~March 31, 2018.~~September 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 nine months ended September 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:


	Nine Months Ended September 30,
	2020		2019
	(in thousands)
Realized gain (loss) on derivatives (1)	$	92,506	$	7,731
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	1,795		(61,430)
Unrealized gain (loss) on derivatives (1)	50,348		(901)
Total commodity derivative gain (loss)	$	144,649	$	(54,600)

(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

Table of Contents

Three Months Ended March 31,
2018 2017
(in thousands)
Realized gain (loss) on derivatives ⁽¹⁾
$ (8,388 ) $ 3,632
Prior year unrealized (gain) loss transferred to realized (gain) loss ⁽¹⁾
6,094
(1,377 )
Unrealized gain (loss) on derivatives ⁽¹⁾
(18,039 ) 14,209
Total commodity derivative gain (loss) $ (20,333 ) $ 16,464
understanding of our hedge position. We also believe that this disclosure allows for a more meaningful comparison to our peers.

~~(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 accurate comparison to our peers.

During the ~~three~~nine months ended ~~March 31, 2018,~~September 30, 2020, approximately ~~75%~~89% of our oil volumes and ~~17%~~22% of our natural gas volumes were subject to financial hedges, which resulted in ~~decreased~~an increase in oil income of ~~$8.5~~$83.7 million and ~~increased~~ natural gas income of ~~$0.1~~$0.5 million. We also amended certain oil hedge contracts to terminate future hedged volumes, which resulted in additional oil income of $8.3 million ~~after settlements of all commodity derivatives.~~during the nine months ended September 30, 2020. During the ~~three~~nine months ended ~~March 31, 2017,~~September 30, 2019, approximately ~~71%~~87% of our oil volumes and ~~45%~~22% of our natural gas volumes were subject to financial hedges, which resulted in ~~increased~~an increase in oil income of ~~$3.7~~$8.4 million and ~~decreased~~a decrease in natural gas income of ~~$0.1~~$0.7 million after ~~settlements~~settlements.

The COVID-19 pandemic caused a severe decline in current and estimated future oil and gas prices during the nine months ended September 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 nine months ended September 30, 2020 and 2019, income tax benefits of $95.9 million and $25.3 million were recognized, respectively. For the nine months ended September 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 ~~commodity derivatives.~~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. For the nine months ended September 30, 2020, we recorded a deferred tax liability of $1.6 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

Current Financial Condition and Liquidity

We have financial covenants associated with our 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, as discussed in the “Going Concern” section in Note 2, based on our financial projections for the twelve month period following the issuance date of these interim consolidated financial statements, it is probable we will breach a financial covenant in our Credit Facility in the second quarter of 2021. If this breach were to occur and we do not receive a waiver from the lenders, all of the amount borrowed under the Credit Facility will become due, and cross-defaults will occur under the indentures to our senior notes. Further, if our independent auditor includes an explanatory paragraph regarding our ability to continue as a “going concern” in its report on our financial statements for the year ending December 31, 2020, this would accelerate a default under our Credit Facility to the first quarter of 2021 at the time our financial statements for the year ending December 31, 2020 are filed and, in turn, result in cross-default under the indentures to our senior notes at that time as well. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.

At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under the Credit Facility. At September 30, 2020, we had cash and cash equivalents of $26.9 million and $140.0 million outstanding under the Credit Facility. On November 2, 2020, as part of our regular semi-annual redetermination, the Credit Facility was amended, which, among other things, reduced the aggregate elected commitment amount to $185.0 million, reduced our borrowing base to $200.0 million and removed the provisions requiring availability under the Credit Facility to be at least $50.0 million. In addition, provisions were amended to disallow us from incurring any additional indebtedness. Our available borrowing capacity as of the date of this filing, November 9, 2020, was $25.6 million, after taking into account outstanding irrevocable letters of credit of $19.4 million.

Sources of Liquidity and Capital Resources

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.

Table of Contents

Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. ~~We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations~~Given the levels of market volatility and ~~under our Amended Credit Facility for our planned uses of capital for the remainder of 2018 and for 2019.~~

At March 31, 2018, we had cash and cash equivalents of $224.7 million and no amounts outstanding under our Amended Credit Facility. At December 31, 2017, we had cash and cash equivalents of $314.5 million and no amounts outstanding under our Amended Credit Facility. Our borrowing base was $300.0 million as of March 31, 2018. Our effective borrowing capacity was reduced by $26.0 million to $274.0 milliondisruption due to ~~an outstanding irrevocable letter~~the COVID-19 pandemic and other recent macro and microeconomic factors, the availability of ~~credit related to a firm transportation agreement.~~

~~On March 19, 2018, we completed~~funds from those markets has diminished substantially. Further, arising from concerns about the ~~Merger, which was effected through the issuance~~stability of ~~100,000,000 shares of the Company's common stock, with a fair value of $484.0 million,~~financial markets generally and the ~~repayment~~solvency of ~~$53.9 million~~borrowers specifically, the cost of ~~Fifth Creek debt. See Note 4 for additional information related~~accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to ~~the Merger.~~provide funding to borrowers.

Cash Flow from Operating Activities

Net cash provided by operating activities for the ~~three~~nine months ended ~~March 31, 2018~~September 30, 2020 and ~~2017~~2019 was ~~$54.3~~$126.7 million and ~~$38.1~~$195.4 million, respectively. The ~~increase~~decrease in net cash provided by operating activities was ~~primarily~~ 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 ~~production revenues, offset by a decrease in~~ cash ~~from derivative settlements.~~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.

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, swaption and cashless collar contracts to receive fixed prices for a portion of our production. At ~~March 31, 2018,~~September 30, 2020, we had in place crude oil swaps covering portions of our ~~2018, 2019~~2020 and ~~2020~~2021 production, ~~and~~ natural gas swaps covering portions of our ~~2018 production.~~

~~At March 31, 2018, the estimated fair value of all~~2020, 2021 and 2022 production, oil roll swaps covering portions of our ~~commodity derivative instruments, summarized~~2020 and 2021 production, crude oil swaptions covering portions of our 2022 production and natural gas cashless collars covering portions of our 2020 and 2021 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the ~~following table, was a net liability of $44.4 million, comprised of current and noncurrent liabilities.~~

Contract
Total
Hedged
Volumes

Quantity
Type

Weighted
Average
Fixed
Price

Index
Price ⁽¹⁾

Fair Market
Value
(in thousands)
Swap Contracts:
2018
Oil 3,602,619
Bbls $ 54.14
WTI $ (32,238 )
Natural gas 1,375,000
MMBtu $ 2.68
NWPL 830
2019
Oil 3,280,434
Bbls $ 55.00
WTI (12,129 )
2020
Oil 183,000
Bbls $ 50.20
WTI (890 )
Total $ (44,427 )


~~(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.

near or foreseeable future. The following table includes all hedges entered into ~~from April 1, 2018 to April 24, 2018:~~through October 30, 2020.

Table of Contents


Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Index Price	Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Index Price (1)
Swap Contracts:
2019
Swaps						Swaps
2020						2020
Oil (2)						Oil (2)	1,150,000	Bbls	$	56.90					WTI
Natural gas						Natural gas	1,840,000	MMBtu	$	1.83					NWPL
2021						2021
Oil	1,277,500	Bbls	$	60.10	WTI	Oil	3,098,000	Bbls	$	54.30					WTI
Natural gas						Natural gas	5,790,000	MMBtu	$	2.13					NWPL
2022						2022

Natural gas						Natural gas	3,650,000	MMBtu	$	2.13					NWPL
Oil Roll Swaps (3)						Oil Roll Swaps (3)
2020						2020
Oil						Oil	138,000	Bbls	$	(1.47)					WTI
2021						2021
Oil						Oil	182,500	Bbls	$	(0.25)					WTI
Swaptions						Swaptions
2022						2022
Oil						Oil	1,092,000	Bbls	$	55.08					WTI
Cashless Collars:						Cashless Collars:
2020						2020

Natural gas						Natural gas	920,000	MMBtu			$	2.00	$	2.70	NWPL
2021						2021

Natural gas						Natural gas	1,800,000	MMBtu			$	2.00	$	4.25	NWPL

(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)We amended certain oil hedge contracts to terminate 161,000 barrels at a weighted average fixed price of $51.91 on October 15, 2020 for cash proceeds of $1.8 million. These volumes are excluded from the table above, but included in the hedge table in Note 7, as they were terminated subsequent to the balance sheet date.

(3)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month price. 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"~~(“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.

Table of Contents

Capital Expenditures

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


	Nine Months Ended September 30,
Basin/Area	2020		2019
	(in millions)
DJ Basin	$	94.9	$	321.9
Other	2.1		4.8
Total	$	97.0	$	326.7

Three Months Ended March 31,
Basin/Area 2018 2017
(in millions)
DJ Basin $ 112.0
$ 58.6
Other 0.1
0.6
Total $ 112.1
$ 59.2


	Nine Months Ended September 30,
	2020		2019
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	—	$	4.3
Drilling, development, exploration and exploitation of oil and natural gas properties	93.3		294.9
Gathering and compression facilities	2.7		11.5
Geologic and geophysical costs	0.5		11.8
Furniture, fixtures and equipment	0.5		4.2
Total	$	97.0	$	326.7

Three Months Ended March 31,
2018 2017
(in millions)
Acquisitions of proved and unproved properties and other real estate $ 0.5
$ 13.5
Drilling, development, exploration and exploitation of oil and natural gas properties 98.1
45.1
Gathering and compression facilities 13.4
0.4
Furniture, fixtures and equipment 0.1
0.2
Total $ 112.1
$ 59.2

~~Our current estimated~~For the three months ending December 31, 2020, we anticipate minimal capital ~~expenditure budget for 2018 is $500.0 million to $550.0 million. The full year 2018 capital budget takes into account the expanded scope of our operations~~expenditures. As oil prices declined significantly due to the COVID-19 pandemic, we deferred drilling and completion ~~of the Merger. The budget includes facilities costs~~activity starting in May 2020 and ~~excludes acquisitions.~~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. If oil, natural gas and NGL prices decline to below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.

We believe that we have sufficient available liquidity with available cash on hand, cash under the Amended Credit Facility and cash flow from operations to fund our 2018 and 2019 capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

~~Merger Financing.~~Our outstanding debt is summarized below:


		As of September 30, 2020						As of December 31, 2019
	Maturity Date	Principal		Unamortized Discount		Carrying Amount		Principal		Unamortized Discount		Carrying Amount
		(in thousands)
Credit Facility	September 14, 2023	$	140,000	$	—	$	140,000	$	140,000	$	—	$	140,000
7.0% Senior Notes	October 15, 2022	350,000		(1,744)		348,256		350,000		(2,372)		347,628
8.75% Senior Notes	June 15, 2025	275,000		(3,202)		271,798		275,000		(3,717)		271,283
Total Long-Term Debt (1)		$	765,000	$	(4,946)	$	760,054	$	765,000	$	(6,089)	$	758,911

(1)See Note 4 for additional information.

Credit Facility. On ~~March 19, 2018, we completed~~May 21, 2020, the ~~Merger with Fifth Creek. The Merger was effected through the issuance of 100,000,000 shares of our common stock, with a fair value of $484.0~~Credit Facility aggregate elected commitment amount and borrowing base were reduced from $500.0 million to $300.0 million and the ~~repayment of $53.9 million of Fifth Creek debt.~~

~~Amended Credit Facility.~~ ~~There~~applicable margins for interest and commitment fee rates were ~~no borrowings~~increased. In addition, provisions were added requiring the availability under the ~~Amended~~ Credit Facility ~~in 2018~~ to ~~date or in 2017.~~ be at least $50.0 million and our weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. We had $140.0 million outstanding under the Credit Facility as of both September 30, 2020 and December 31, 2019. Our available borrowing capacity was $87.7 million as of September 30, 2020 after taking into account the $50.0 million minimum availability requirement as well as letters of credit totaling $22.3 million, which were issued as credit support for future payments under contractual obligations.

On ~~May 1, 2018,~~November 2, 2020, as part of our regular semi-annual redetermination, the Credit Facility was amended, which, among other things, reduced the aggregate elected commitment amount to $185.0 million, reduced our borrowing base to $200.0 million and removed the provisions requiring availability under the Credit Facility to be at least $50.0 million. In addition, provisions were amended to disallow us from incurring any additional indebtedness. Our available borrowing capacity as of the date of this filing, November 9, 2020, was ~~re-affirmed at $300.0~~$25.6 million, ~~based~~after taking into account outstanding irrevocable letters of credit of $19.4 million.

Table of Contents

The current maturity date of the Credit Facility is July 16, 2022. While the stated maturity date in the 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 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 ~~Bill Barrett's proved reserves in place at December 31, 2017~~October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the ~~Company's commodity hedge position. We plan~~notes represent “Permitted Debt”, the maturity date specified in the Credit Facility is accelerated to ~~incorporate~~ the ~~proved reserves and development~~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 ~~assets acquired in~~lenders and is subject to regular redetermination on or about April and October 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 ~~Merger at our next re-determination, which~~borrowing base is reduced below the then-outstanding amount under the Credit Facility, we will ~~likely have~~be required to repay the excess of the outstanding amount over the borrowing base over a ~~positive effect on our future~~period of four months. The borrowing ~~base. Borrowing bases are~~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 ~~our~~the lenders, as well as any other outstanding debt. ~~Lower commodity prices will generally result in a lower borrowing base.~~

Going Concern. We are currently in compliance with all financial covenants ~~and have complied with all financial covenants since issuance. We expect to be~~under our Credit Facility. However, as discussed in ~~compliance with all financial covenants~~the “Going Concern” section in Note 2, based on our financial projections for the twelve month period following the issuance date of these interim consolidated financial statements, it is probable we will breach a financial covenant in our Credit Facility in the second quarter of 2021. If this breach were to occur and we do not receive a waiver from the lenders, all of the amount borrowed under the Credit Facility will become due, and cross-defaults will occur under the indentures to our senior notes. Further, if our independent auditor includes an explanatory paragraph regarding our ability to continue as a “going concern” in its report on our financial statements for the year ending December 31, 2020, this would accelerate a default under our Credit Facility to the first quarter of 2021 at the time our financial statements for the year ending December 31, 2020 are filed and, in turn, result in cross-default under the indentures to our senior notes at that time as well. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.

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 2018 ~~budget at current commodity prices.~~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.

~~Our outstanding~~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 issecurities 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 ~~below:~~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, and 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.

As of March 31, 2018 As of December 31, 2017
Maturity Date Principal Unamortized
Discount Carrying
Amount Principal Unamortized
Discount Carrying
Amount
(in thousands)
Amended Credit Facility April 8, 2020 $ —
$ —
$ —
$ —
$ —
$ —
7.0% Senior Notes October 15, 2022 350,000
(3,837 ) 346,163
350,000
(4,033 ) 345,967
8.75% Senior Notes June 15, 2025 275,000
(4,919 ) 270,081
275,000
(5,080 ) 269,920
Lease Financing Obligation August 10, 2020 2,212
—
2,212
2,328
(2 ) 2,326
Total Debt $ 627,212
$ (8,756 ) $ 618,456
$ 627,328
$ (9,115 ) $ 618,213
Less: Current Portion of Long-Term Debt 2,212
—
2,212
469
—
469
Total Long-Term Debt ⁽¹⁾
$ 625,000
$ (8,756 ) $ 616,244
$ 626,859
$ (9,115 ) $ 617,744


~~(1)~~	~~See Note 5 for additional information.~~

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~~Moody’s Investor Services and Standard & ~~Poor's~~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

Table of Contents

Notes or 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities ~~will~~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 ~~March 31, 2018~~September 30, 2020 is provided in the following table:


	Payments Due by Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	Twelve Months Ended September 30, 2021		Twelve Months Ended September 30, 2022		Twelve Months Ended September 30, 2023		Twelve Months Ended September 30, 2024		Twelve Months Ended September 30, 2025		After September 30, 2025
	(in thousands)
Notes payable (1) (2)	$	252	$	—	$	140,000	$	—	$	—	$	—	$	140,252
7.0% Senior Notes (2) (3)	24,500		24,500		362,250		—		—		—		411,250
8.75% Senior Notes (2) (4)	24,063		24,063		24,063		24,063		299,061		—		395,313


Firm transportation agreements (5)	23,673		11,886		14,600		14,640		8,480		—		73,279
Gas gathering and processing agreements (6) (7)	2,380		1,942		—		—		—		—		4,322
Asset retirement obligations (8)	2,136		2,000		2,006		2,125		2,128		16,154		26,549
Derivative liability (9)	—		601		—		—		—		—		601
Operating leases (10)	2,688		2,442		2,199		2,065		2,166		5,933		17,493
Other (11)	1,378		1,285		11,245		15,725		—		—		29,633
Total	$	81,070	$	68,719	$	556,363	$	58,618	$	311,835	$	22,087	$	1,098,692

(1)Included in notes payable is the outstanding principal amount under our Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Credit Facility because the 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 Credit Facility is July 16, 2022. While the stated maturity date in the 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 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 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 $17.3 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)The payment dates could be accelerated. See the “Going Concern” section in Note 2.

(3)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.

(4)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.

(5)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.

(6)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.

(7)Includes reimbursement obligations of $1.8 million. The reimbursement obligations require us to pay a monthly gathering

and processing fee per Mcf of production to reimburse midstream entities for costs to construct gas gathering and

processing facilities. If the costs are not reimbursed by us via the monthly gathering and processing fees, we must pay the

difference.

(8)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.

(9)Derivative liability represents the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our

Unaudited Consolidated Balance Sheets as of September 30, 2020. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and

Table of Contents

Payments Due by Year
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
Twelve Months Ended March 31, 2019 Twelve Months Ended March 31, 2020 Twelve Months Ended March 31, 2021 Twelve Months Ended March 31, 2022 Twelve Months Ended March 31, 2023 After
March 31, 2023
(in thousands)
Notes payable ⁽¹⁾
$ 46
$ —
$ —
$ —
$ —
$ —
$ 46
7.0% Senior Notes ⁽²⁾
24,500
24,500
24,500
24,500
374,500
—
472,500
8.75% Senior Notes ⁽³⁾
24,063
24,063
24,063
24,063
24,063
335,154
455,469
Lease Financing Obligation ⁽⁴⁾
2,272
—
—
—
—
—
2,272
Office and office equipment leases and other ⁽⁵⁾
4,122
1,141
720
445
445
79
6,952
Firm transportation agreements ⁽⁶⁾
18,456
18,691
18,691
6,230
—
—
62,068
Gas gathering and processing agreement ⁽⁷⁾
2,553
2,315
2,124
1,498
—
—
8,490
Asset retirement obligations ⁽⁸⁾
1,443
1,042
1,167
1,153
1,200
19,345
25,350
Derivative liability ⁽⁹⁾
35,866
7,941
620
—
—
—
44,427
Total $ 113,321
$ 79,693
$ 71,885
$ 57,889
$ 400,208
$ 354,578
$ 1,077,574
Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018 and in "Commodity Hedging Activities" above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(10)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.


~~(1)~~	Notes payable includes interest on a $26.0 million letter of credit that accrues interest at 2.0% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term of the letter of credit is April 30, 2018. There is currently no balance outstanding under the Amended Credit Facility due April 9, 2020.


~~(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)~~	The Lease Financing Obligation is calculated based on the aggregate undiscounted minimum future lease payments, which include both an interest and principal component. We have elected to exercise the early buyout option pursuant to which we will purchase the equipment for $1.8 million on February 10, 2019.


~~(5)~~	The lease for our principal office in Denver, Colorado extends through March 2019. Due to the Merger, we acquired the office lease of Fifth Creek in Greenwood Village, Colorado which extends through July 2023.


~~(6)~~	We have entered into contracts that provide firm transportation capacity on pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount of gas we deliver to the processing facility or pipeline.


~~(7)~~	We have entered into 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 those volumes regardless of the amount delivered.

~~(8)~~

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 Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

~~(9)~~

Derivative liability represents the net fair value for oil, gas and NGL commodity derivatives presented as liabilities in our Unaudited Consolidated Balance Sheets as of March 31, 2018. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of Bill Barrett's Annual Report on Form 10-K for the year ended December 31, 2017 and in "Commodity Hedging Activities" above in this Quarterly Report on Form 10-Q for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(11)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, we 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 ~~March 31, 2018.~~September 30, 2020.

Trends and Uncertainties

We refer you to the corresponding section in Part II, Item 7 of ~~Bill Barrett's~~our Annual Report on Form 10-K for the year ended December 31, ~~2017~~2019 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see ~~"Risk Factors"~~“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 nine months ended September 30, 2020 were mitigated from price declines by hedges in place on 96% and 89%, respectively, of our oil production. We currently have hedged 1,150,000 barrels 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 2,760,000 MMbtu of our expected remaining 2020 natural gas production and 7,590,000 MMbtu and 3,650,000 of our expected 2021 and 2022 natural gas production, respectively. 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.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of ~~Bill Barrett's~~our Annual Report on Form 10-K for the year ended December 31, ~~2017~~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"~~“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.

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 nine months ended September 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 ~~three~~nine months ended ~~March 31, 2018,~~September 30, 2020, our income before income taxes would have decreased by approximately ~~$0.2~~$0.6 million for each ~~$1.00~~$5.00 per barrel decrease in crude oil prices, approximately ~~$0.2~~$1.0 million for each $0.10 decrease per MMBtu in natural gas prices and approximately ~~$0.3~~$1.7 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.~~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 price (“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 ~~April 24, 2018,~~October 30, 2020, we have ~~financial derivative instruments~~swap and swaption contracts related to oil and natural gas volumes in place for the following periods ~~indicated.~~ indicated:


	October – 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) (1)	1,150,000	$	56.90	3,098,000	$	54.30	—	$	—
Natural Gas (MMbtu)	1,840,000	$	1.83	5,790,000	$	2.13	3,650,000	$	2.13

Oil Roll Swaps (2)
Oil (Bbls)	138,000	$	(1.47)	182,500	$	(0.25)	—	$	—
Swaptions
Oil (Bbls)	—	$	—	—	$	—	1,092,000	$	55.08

(1)We amended certain oil hedge contracts to terminate 161,000 barrels for October – December 2020 at a weighted average fixed price of $51.91 on October 15, 2020 for cash proceeds of $1.8 million. These volumes are excluded from the table above, but included in the hedge table in Note 7, as they were terminated subsequent to the balance sheet date.

Table of Contents

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

As of October 30, 2020, we have cashless collar contracts for natural gas volumes in place for the following periods indicated:


	October – December 2020					For the year 2021
	Derivative Volumes	Weighted Average Floor		Weighted Average Ceiling		Derivative Volumes	Weighted Average Floor		Weighted Average Ceiling
Cashless Collars

Natural Gas (MMbtu)	920,000	$	2.00	$	2.70	1,800,000	$	2.00	$	4.25

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

Interest Rate Risk

At September 30, 2020, we had $140.0 million outstanding under our Credit Facility, which bears interest at floating rates. The weighted average annual interest rate incurred on this debt for the nine months ended September 30, 2020 was 3.2%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2020 would have resulted in an estimated $1.2 million increase in interest expense assuming a similar average debt level to the nine months ended September 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 September 30, 2020.

April – December 2018 For the year 2019 For the year 2020
Derivative
Volumes Weighted Average Price Derivative Volumes Weighted Average Price Derivative Volumes Weighted Average Price
Oil (Bbls) 3,602,619
$ 54.14
4,557,934
$ 56.43
183,000
$ 50.20
Natural Gas (MMbtu) 1,375,000
$ 2.68
—
$ —
—
$ —

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of ~~March 31, 2018,~~September 30, 2020, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and ~~Principal~~Chief Financial Officer, of the 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 ~~Principal~~Chief Financial Officer concluded that our disclosure controls and procedures are effective as of ~~March 31, 2018.~~September 30, 2020.

Changes in Internal Controls. There ~~has been~~was no change in our internal control over financial reporting during the ~~first fiscal~~third quarter of ~~2018~~2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings.

We are ~~not a party to any material pending~~involved in various legal or governmental proceedings ~~other than~~in the ordinary ~~routine litigation incidental~~course of business. These proceedings 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 ~~business.~~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.~~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 Purchase Agreement. We are seeking monetary damages in an amount not yet specified.

Disclosure of certain environmental matters is 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 $1.1 million associated with the NOAVs, as they are probable and reasonably estimable.

Item 1A. Risk Factors.

~~As of the date of this filing, there have been no material changes or updates~~Please refer to the ~~risk factors previously disclosed in the "Risk Factors"~~“Risk Factors” section of ~~Bill Barrett's~~our Annual Report on Form 10-K for the year ended December 31, ~~2017.~~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 ~~Bill Barrett's~~our Annual Report on Form 10-K for the year ended December 31, ~~2017~~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.

Our potential inability to comply with the financial covenants in our Credit Facility have raised substantial doubt about our ability to continue as a going concern.

We have financial covenants associated with our 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, as discussed in the “Going Concern” section in Note 2, based on our financial projections for the twelve month period following the issuance date of these interim consolidated financial statements, it is probable we will breach a financial covenant in our Credit Facility in the second quarter of 2021.If this breach were to occur and we do not receive a waiver from the lenders, all of the amount borrowed under the Credit Facility will become due, and cross-defaults will occur under the indentures to our senior notes. Further, if our independent auditor includes an explanatory paragraph regarding our ability to continue as a “going concern” in its report on our financial statements for the year ending December 31, 2020, this would accelerate a default under our Credit Facility to the first quarter of 2021 at the time our financial statements for the year ending December 31, 2020 are filed and, in turn, result in cross-default under the indentures to our senior notes at that time as well. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default.

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

Table of Contents

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. Crude prices averaged $40.93 per barrel for three months ended September 30, 2020. 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 nine months ended September 30, 2020 were mitigated by hedges in place on 96% and 89%, 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 liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. In addition, our ability to comply with financial covenants will be adversely affected and impact our ability to continue as a going concern. 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 nine months ended September 30, 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.

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.

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. 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. On October 30, 2020, we completed a 1-for-50 reverse stock split of our common stock to satisfy this requirement. The reverse stock split reduced the number of shares of our outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares, subject to adjustment of the rounding of fractional shares.

Table of Contents

On November 4, 2020, we were notified by the NYSE that our average market capitalization was less than $50 million over the prior 30-consecutive trading day period along with a stockholders’ equity balance of less than $50 million. As set forth in the notice, as of November 3, 2020, our prior 30-consecutive trading day average market capitalization was $42.5 million and our last reported shareholders’ equity as of June 30, 2020 was $2.2 million. In accordance with NYSE listing requirements, we will submit a plan within 45 days advising the NYSE of definitive action we have taken, or are taking, to bring us into conformity within 18 months. The NYSE will review our plan and, within 45 days, make a determination as to whether we have made a reasonable demonstration of our ability to come into conformity within 18 months. If our plan is not submitted on a timely basis or is not accepted, the NYSE will initiate delisting proceedings. If the NYSE accepts our plan, our common stock will continue to be listed and traded on the NYSE during the cure period, subject to our compliance with the plan and other continued listing standards. The NYSE will review our compliance with the plan on a quarterly basis. If we fail to comply with the plan or do not meet continued listing standards at the end of the 18-month cure period, we will be subject to the prompt initiation of NYSE suspension and delisting procedures. Further, if our average market capitalization goes below $15 million over a 30-consecutive trading day period, there is no cure period for continued listing on the NYSE.

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 ~~March 31, 2018:~~September 30, 2020:


Period	Total Number of Shares (1)(2)	Weighted Average Price Paid Per Share (2)		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
July 1 – 31, 2020	884	$	16.00	—	—
August 1 – 31, 2020	26	20.00		—	—
September 1 – 30, 2020	5	16.50		—	—
Total	915	16.00		—	—

(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.

(2)All share and per share information has been retroactively adjusted to reflect a 1-for-50 reverse stock split effective October 30, 2020. See Note 12 for additional information.

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
January 1 – 31, 2018 165
$ 5.26
—
—
February 1 – 28, 2018 269,042
5.36
—
—
March 1 – 31, 2018 4,145
4.69
—
—
Total 273,352
5.35
—
—


~~(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.

Table of Contents

Item 6. Exhibits.


Exhibit Number		Description of Exhibits
10.1+		Form of Director’s Restricted Common Stock Unit Award Agreement.

~~Exhibit~~ ~~Number~~ 10.2+		~~Description of Exhibits~~
~~4.1~~	~~Specimen Certificate~~Form of ~~Common Stock.~~Performance Unit Grant Agreement.

~~10.1~~10.3+		Form of ~~Change in Control Severance Protection~~Restricted Common Stock Award Agreement.

~~10.2~~22		~~Form~~Subsidiary Guarantors and Issuers of ~~Indemnification Agreement.~~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 ~~Principal~~Chief Financial Officer.

32.1		Section 1350 Certification of Chief Executive Officer.

32.2		Section 1350 Certification of ~~Principal~~Chief Financial Officer.

101.INS		~~XBRL~~ 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).


+			Indicates a management contract or compensatory plan or arrangement, as required by Item 15(a)(3).

Table of Contents

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:

~~May 8, 2018~~November 9, 2020

By:

/s/ R. Scot Woodall

R. Scot Woodall

Chief Executive Officer and President

(Principal Executive Officer)

Date:

~~May 8, 2018~~November 9, 2020

By:

/s/ ~~David R. Macosko~~William M. Crawford

~~David R. Macosko~~William M. Crawford

~~Senior Vice President-Accounting~~Chief Financial Officer

(Principal Accounting Officer)



	March 31, 2018			December 31, 2017
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	224,692		$	314,466
Accounts receivable, net of allowance for doubtful accounts	50,268			51,415
Prepayments and other current assets	2,393			1,782
Total current assets	277,353			367,663
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	1,568,921			1,361,168
Unproved oil and gas properties, excluded from amortization	708,917			84,676
Furniture, equipment and other	18,921			17,899
	2,296,759			1,463,743
Accumulated depreciation, depletion, amortization and impairment	(485,317		)	(444,863		)
Total property and equipment, net	1,811,442			1,018,880
Deferred financing costs and other noncurrent assets	3,679			4,163
Total	$	2,092,474		$	1,390,706
Liabilities and Stockholders' Equity:
Current liabilities:
Accounts payable and other accrued liabilities	$	135,925		$	84,055
Amounts payable to oil and gas property owners	30,852			16,594
Production taxes payable	35,533			26,876
Derivative liabilities	35,866			20,940
Current portion of long-term debt	2,212			469
Total current liabilities	240,388			148,934
Long-term debt, net of debt issuance costs	616,244			617,744
Asset retirement obligations	23,907			16,097
Deferred income taxes	137,111			—
Derivatives and other noncurrent liabilities	14,484			9,377
Commitments and contingencies (Note 13)
Stockholders' equity:
Common stock, $0.001 par value; authorized 400,000,000 and 300,000,000 shares at March 31, 2018 and December 31, 2017, respectively; 212,008,260 and 110,363,539 shares issued and outstanding at March 31, 2018 and December 31, 2017, respectively, with 2,657,535 and 1,394,868 shares subject to restrictions, respectively	209			109
Additional paid-in capital	1,766,130			1,279,507
Retained earnings (accumulated deficit)	(705,999		)	(681,062		)
Treasury stock, at cost: zero shares at March 31, 2018 and December 31, 2017	—			—
Total stockholders' equity	1,060,340			598,554
Total	$	2,092,474		$	1,390,706



	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total Stockholders' Equity
Balance at December 31, 2016	$	74	$	1,113,797		$	(542,328	)	$	—		$	571,543
Cumulative effect of accounting change	—		180			(509		)	—			(329		)
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	1		—			—			(1,253		)	(1,252		)
Stock-based compensation	—		7,099			—			—			7,099
Retirement of treasury stock	—		(1,253		)	—			1,253			—
Exchange of senior notes for shares of common stock	11		48,981			—			—			48,992
Issuance of common stock, net of offering costs	23		110,703			—			—			110,726
Net income (loss)	—		—			(138,225		)	—			(138,225		)
Balance at December 31, 2017	109		1,279,507			(681,062		)	—			598,554
Exercise of options, restricted stock activity and shares exchanged for exercise and tax withholding	—		—			—			(1,462		)	(1,462		)
Stock-based compensation ⁽¹⁾	—		4,185			—			—			4,185
Retirement of treasury stock	—		(1,462		)	—			1,462			—
Issuance of common stock, merger	100		483,900			—			—			484,000
Net income (loss)	—		—			(24,937		)	—			(24,937		)
Balance at March 31, 2018	$	209	$	1,766,130		$	(705,999	)	$	—		$	1,060,340



	As of March 31, 2018			As of December 31, 2017
	(in thousands)
Oil, gas and NGL sales	$	41,056		$	36,569
Due from joint interest owners	9,081			14,779
Other	132			270
Allowance for doubtful accounts	(1		)	(203		)
Total accounts receivable	$	50,268		$	51,415



	March 19, 2018
	(in thousands)
Purchase Price:
Fair value of common stock issued	$	484,000
Plus: Repayment of Fifth Creek debt	53,900
Total purchase price	537,900

Plus Liabilities Assumed:
Accounts payable and accrued liabilities	24,469
Current unfavorable contract	2,651
Other current liabilities	13,852
Asset retirement obligations	7,361
Long-term deferred tax liability	137,111
Long-term unfavorable contract	4,449
Other noncurrent liabilities	2,354
Total purchase price plus liabilities assumed	$	730,147

Fair Value of Assets Acquired:
Cash	543
Accounts receivable	8,019
Oil and Gas Properties:
Proved oil and gas properties	105,702
Unproved oil and gas properties	607,526
Asset Retirement Obligations	7,361
Furniture, equipment and other	931
Other noncurrent assets	65
Total asset value	$	730,147



As of December 31, 2017	$	17,586
Liabilities incurred ⁽¹⁾	7,795
Liabilities settled	(282		)
Accretion expense	251
Revisions to estimate	—
As of March 31, 2018	$	25,350
Less: Current asset retirement obligations	1,443
Long-term asset retirement obligations	$	23,907



	As of March 31, 2018
	Parent Guarantor		Subsidiary Issuer		Subsidiary Guarantor		Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	—	$	224,692	$	—	$	—		$	224,692
Accounts receivable, net of allowance for doubtful accounts	—		50,268		—		—			50,268
Other current assets	—		2,393		—		—			2,393
Property and equipment, net	—		1,809,548		1,894		—			1,811,442
Intercompany receivable	—		854		—		(854		)	—
Investment in subsidiaries	1,060,340		1,040		—		(1,061,380		)	—
Noncurrent assets	—		3,679		—		—			3,679
Total assets	$	1,060,340	$	2,092,474	$	1,894	$	(1,062,234	)	$	2,092,474
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities	$	—	$	135,925	$	—	$	—		$	135,925
Other current liabilities	—		104,463		—		—			104,463
Intercompany payable	—		—		854		(854		)	—
Long-term debt	—		616,244		—		—			616,244
Deferred income taxes	—		137,111		—		—			137,111
Other noncurrent liabilities	—		38,391		—		—			38,391
Stockholders' equity	1,060,340		1,060,340		1,040		(1,061,380		)	1,060,340
Total liabilities and stockholders' equity	$	1,060,340	$	2,092,474	$	1,894	$	(1,062,234	)	$	2,092,474



	As of December 31, 2017
	Parent Issuer		Subsidiary Guarantors		Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	314,466	$	—	$	—		$	314,466
Accounts receivable, net of allowance for doubtful accounts	51,415		—		—			51,415
Other current assets	1,782		—		—			1,782
Property and equipment, net	1,016,986		1,894		—			1,018,880
Intercompany receivable	854		—		(854		)	—
Investment in subsidiaries	1,040		—		(1,040		)	—
Noncurrent assets	4,163		—		—			4,163
Total assets	$	1,390,706	$	1,894	$	(1,894	)	$	1,390,706
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities	$	84,055	$	—	$	—		$	84,055
Other current liabilities	64,879		—		—			64,879
Intercompany payable	—		854		(854		)	—
Long-term debt	617,744		—		—			617,744
Other noncurrent liabilities	25,474		—		—			25,474
Stockholders' equity	598,554		1,040		(1,040		)	598,554
Total liabilities and stockholders' equity	$	1,390,706	$	1,894	$	(1,894	)	$	1,390,706



	Three Months Ended March 31, 2018				Three Months Ended March 31, 2017				% Increase (Decrease)
	Oil	NGL	Natural Gas	Total	Oil	NGL	Natural Gas	Total	Oil		NGL		Natural Gas		Total
	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)	(MBbls)	(MMcf)	(MBoe)	(MBbls)		(MBbls)		(MMcf)		(MBoe)
DJ Basin	1,137	350	2,562	1,914	679	291	1,842	1,277	67	%	20	%	39	%	50	%
Other ⁽¹⁾	—	—	—	—	146	2	48	156	*nm		*nm		*nm		*nm
Total	1,137	350	2,562	1,914	825	293	1,890	1,433	38	%	19	%	36	%	34	%



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
January 1 – 31, 2018	165	$	5.26	—	—
February 1 – 28, 2018	269,042	5.36		—	—
March 1 – 31, 2018	4,145	4.69		—	—
Total	273,352	5.35		—	—