HighPoint Resources (HPR) 10-Q 2019 Q3 Quarterly report

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549 

FORM 10-Q

(Mark One)

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

For the quarterly period ended September 30, 2019

OR

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

For the transition period from to

Commission file number 333-222275

HighPoint Resources Corporation

(Exact name of registrant as specified in its charter)

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

555 17th Street, Suite 3700

Denver, Colorado 80202

(Address of principal executive offices, including zip code)

(303) 293-9100

(Registrant's telephone number, including area code)

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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    þ  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 accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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

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

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

There were 213,675,011 shares of $0.001 par value common stock outstanding on October 21, 2019.

INDEX TO FINANCIAL STATEMENTS

PART I. FINANCIAL INFORMATION
Item 1.	Consolidated Financial Statements (Unaudited)	3
Item 2.	Management's Discussion and Analysis of Financial Condition and Results of Operations	29
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	42
Item 4.	Controls and Procedures	43
PART II. OTHER INFORMATION
Item 1.	Legal Proceedings	43
Item 1A.	Risk Factors	43
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	44
Item 3.	Defaults Upon Senior Securities	44
Item 4.	Mine Safety Disclosures	44
Item 5.	Other Information	44
Item 6.	Exhibits	45
SIGNATURES		46

2

PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

(UNAUDITED)

	September 30, 2019			December 31, 2018
	(in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents	$	19,568		$	32,774
Accounts receivable, net of allowance for doubtful accounts	59,427			72,943
Derivative assets	36,114			81,166
Prepayments and other current assets	4,688			2,898
Total current assets	119,797			189,781
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties	2,581,796			2,195,310
Unproved oil and gas properties, excluded from amortization	393,910			468,208
Furniture, equipment and other	29,152			20,662
	3,004,858			2,684,180
Accumulated depreciation, depletion, amortization and impairment	(876,869		)	(654,657		)
Total property and equipment, net	2,127,989			2,029,523
Derivative assets	10,010			27,289
Other noncurrent assets	5,831			5,867
Total	$	2,263,627		$	2,252,460
Liabilities and Stockholders' Equity:
Current Liabilities:
Accounts payable and accrued liabilities	$	88,524		$	131,379
Amounts payable to oil and gas property owners	39,008			55,792
Production taxes payable	58,076			59,155
Current portion of long-term debt	—			1,859
Total current liabilities	185,608			248,185
Long-term debt, net of debt issuance costs	793,530			617,387
Asset retirement obligations	23,347			27,330
Deferred income taxes	114,263			139,534
Other noncurrent liabilities	17,316			7,926
Commitments and contingencies (Note 12)
Stockholders' Equity:
Common stock, $0.001 par value; authorized 400,000,000 shares; 213,676,102 and 212,477,101 shares issued and outstanding at September 30, 2019 and December 31, 2018, respectively, with 2,983,031 and 2,912,166 shares subject to restrictions, respectively	211			210
Additional paid-in capital	1,776,219			1,771,730
Retained earnings (accumulated deficit)	(646,867		)	(559,842		)
Treasury stock, at cost: zero shares at September 30, 2019 and December 31, 2018	—			—
Total stockholders' equity	1,129,563			1,212,098
Total	$	2,263,627		$	2,252,460

See notes to Unaudited Consolidated Financial Statements.

3

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

(UNAUDITED)

	Three Months Ended September 30,						Nine Months Ended September 30,
	2019			2018			2019			2018
	(in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production	$	121,281		$	131,585		$	330,472		$	322,534
Other operating revenues, net	1			(459		)	374			(200		)
Total operating revenues	121,282			131,126			330,846			322,334
Operating Expenses:
Lease operating expense	8,385			7,237			30,434			21,082
Gathering, transportation and processing expense	1,611			1,398			5,076			2,829
Production tax expense	7,868			11,504			20,666			26,363
Exploration expense	56			19			93			39
Impairment, dry hole costs and abandonment expense	1,170			184			2,487			609
(Gain) loss on sale of properties	—			74			2,901			1,046
Depreciation, depletion and amortization	84,948			58,946			230,170			152,106
Unused commitments	4,418			4,574			13,239			13,684
General and administrative expense	11,048			12,696			36,109			34,427
Merger transaction expense	2,078			100			4,492			6,140
Other operating expenses, net	230			(764		)	210			(716		)
Total operating expenses	121,812			95,968			345,877			257,609
Operating Income (Loss)	(530		)	35,158			(15,031		)	64,725
Other Income and Expense:
Interest and other income	94			451			562			1,843
Interest expense	(15,167		)	(13,165		)	(43,227		)	(39,348		)
Commodity derivative gain (loss)	31,047			(51,547		)	(54,600		)	(128,166		)
Gain (loss) on extinguishment of debt	—			(257		)	—			(257		)
Total other income and expense	15,974			(64,518		)	(97,265		)	(165,928		)
Income (Loss) before Income Taxes	15,444			(29,360		)	(112,296		)	(101,203		)
(Provision for) Benefit from Income Taxes	(4,330		)	—			25,271			—
Net Income (Loss)	$	11,114		$	(29,360	)	$	(87,025	)	$	(101,203	)
Net Income (Loss) Per Common Share, Basic	$	0.05		$	(0.14	)	$	(0.41	)	$	(0.56	)
Net Income (Loss) Per Common Share, Diluted	$	0.05		$	(0.14	)	$	(0.41	)	$	(0.56	)
Weighted Average Common Shares Outstanding, Basic	210,549,653			209,501,887			210,288,446			181,144,822
Weighted Average Common Shares Outstanding, Diluted	210,937,271			209,501,887			210,288,446			181,144,822

See notes to Unaudited Consolidated Financial Statements.

4

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

(UNAUDITED)

 

	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(87,025	)	$	(101,203	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization	230,170			152,106
Deferred income taxes	(25,271		)	—
Impairment, dry hole costs and abandonment expense	2,487			609
Commodity derivative (gain) loss	54,600			128,166
Settlements of commodity derivatives	7,731			(42,628		)
Stock compensation and other non-cash charges	9,501			5,813
Amortization of deferred financing costs	1,917			1,729
(Gain) loss on extinguishment of debt	—			257
(Gain) loss on sale of properties	2,901			1,046
Change in operating assets and liabilities:
Accounts receivable	13,488			(8,789		)
Prepayments and other assets	(1,109		)	(1,421		)
Accounts payable, accrued and other liabilities	3,867			(25,287		)
Amounts payable to oil and gas property owners	(16,784		)	33,804
Production taxes payable	(1,079		)	15,983
Net cash provided by (used in) operating activities	195,394			160,185
Investing Activities:
Additions to oil and gas properties, including acquisitions	(375,976		)	(322,614		)
Additions of furniture, equipment and other	(3,958		)	(616		)
Repayment of debt associated with merger, net of cash acquired	—			(53,357		)
Proceeds from sale of properties	1,334			(221		)
Other investing activities	(1,400		)	232
Net cash provided by (used in) investing activities	(380,000		)	(376,576		)
Financing Activities:
Proceeds from debt	200,000			—
Principal payments on debt	(26,859		)	(350		)
Other financing activities	(1,741		)	(4,745		)
Net cash provided by (used in) financing activities	171,400			(5,095		)
Increase (Decrease) in Cash and Cash Equivalents	(13,206		)	(221,486		)
Beginning Cash and Cash Equivalents	32,774			314,466
Ending Cash and Cash Equivalents	$	19,568		$	92,980

See notes to Unaudited Consolidated Financial Statements.

5

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY

(UNAUDITED)

(In thousands)

	Three Months Ended September 30, 2019 and 2018
	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total Stockholders' Equity
Balance at June 30, 2019	$	210	$	1,774,164		$	(657,981	)	$	—		$	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			—
Net income (loss)	—		—			11,114			—			11,114
Balance at September 30, 2019	$	211	$	1,776,219		$	(646,867	)	$	—		$	1,129,563
Balance at June 30, 2018	$	209	$	1,767,899		$	(752,905	)	$	—		$	1,015,203
Restricted stock activity and shares exchanged for tax withholding	1		—			—			(43		)	(42		)
Stock-based compensation	—		1,996			—			—			1,996
Retirement of treasury stock	—		(43		)	—			43			—
Net income (loss)	—		—			(29,360		)	—			(29,360		)
Balance at September 30, 2018	$	210	$	1,769,852		$	(782,265	)	$	—		$	987,797
	Nine Months Ended September 30, 2019 and 2018
	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total Stockholders' Equity
Balance at December 31, 2018	$	210	$	1,771,730		$	(559,842	)	$	—		$	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			—
Net income (loss)	—		—			(87,025		)	—			(87,025		)
Balance at September 30, 2019	$	211	$	1,776,219		$	(646,867	)	$	—		$	1,129,563
Balance at December 31, 2017	$	109	$	1,279,507		$	(681,062	)	$	—		$	598,554
Restricted stock activity and shares exchanged for tax withholding	1		—			—			(1,533		)	(1,532		)
Stock-based compensation	—		7,978			—			—			7,978
Retirement of treasury stock	—		(1,533		)	—			1,533			—
Issuance of common stock, merger	100		483,900			—			—			484,000
Net income (loss)	—		—			(101,203		)	—			(101,203		)
Balance at September 30, 2018	$	210	$	1,769,852		$	(782,265	)	$	—		$	987,797

See notes to Unaudited Consolidated Financial Statements.

6

HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

(UNAUDITED)

September 30, 2019

1. Organization

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

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company's interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company's Annual Report on Form 10-K for the year ended December 31, 2018 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Annual Report on Form 10-K.

Use of Estimates. In the course of preparing the Company's financial statements in accordance with GAAP, management makes various assumptions, judgments and estimates to determine the reported amount of assets, liabilities, revenues and expenses and in the disclosure of commitments and contingencies. Changes in these assumptions, judgments and estimates will occur as a result of the passage of time and the occurrence of future events and, accordingly, actual results could differ from amounts initially established.

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization ("DD&A"), the amount of expected future cash flows used in determining 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 tax assets, the timing of dry hole costs, impairments of proved and unproved oil and gas properties and fair values of derivative instruments and stock-based payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of September 30, 2019			As of December 31, 2018
	(in thousands)
Oil, gas and NGL sales	$	49,840		$	44,860
Due from joint interest owners	8,879			27,435
Other	709			754
Allowance for doubtful accounts	(1		)	(106		)
Total accounts receivable	$	59,427		$	72,943

7

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

	As of September 30, 2019			As of December 31, 2018
	(in thousands)
Proved properties	$	679,200		$	663,485
Wells and related equipment and facilities	1,786,836			1,438,092
Support equipment and facilities	91,915			75,392
Materials and supplies	23,845			18,341
Total proved oil and gas properties	$	2,581,796		$	2,195,310
Unproved properties	319,265			328,409
Wells and facilities in progress	74,645			139,799
Total unproved oil and gas properties, excluded from amortization	$	393,910		$	468,208
Accumulated depreciation, depletion, amortization and impairment	(868,529		)	(642,645		)
Total oil and gas properties, net	$	2,107,177		$	2,020,873

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

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

	As of September 30, 2019		As of December 31, 2018
	(in thousands)
Accrued drilling, completion and facility costs	$	42,805	$	69,830
Accrued lease operating, gathering, transportation and processing expenses	9,039		6,970
Accrued general and administrative expenses	7,130		8,774
Accrued interest payable	18,901		6,758
Accrued merger transaction expenses	—		550
Trade payables	3,929		31,057
Operating lease liability	985		—
Other	5,735		7,440
Total accounts payable and accrued liabilities	$	88,524	$	131,379

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

8

Revenue Recognition. All of the Company's sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company's contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company's contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company's contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of September 30, 2019, the Company had open contracts with customers with terms of 1 month to 19 years, as well as evergreen contracts that renew on a periodic basis if not canceled by the Company or the customer. The Company's contracts with customers typically require payment within one month of delivery.

Under the Company's contracts with customers, natural gas and its components, including NGLs, are either sold to a midstream entity (which processes the natural gas and subsequently sells the resulting residue gas and NGLs) or are sold to a gas or NGL purchaser after being processed by a third party for a fee. Regardless of the contract structure type, the terms of these contracts compensate the Company for the value of the residue gas and NGLs at current market prices for each product. The Company's oil is sold to multiple oil purchasers at specific delivery points at or near the wellhead. All costs incurred to gather, transport and/or process the Company's oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and therefore are recorded in oil, gas and NGL production revenues in the Unaudited Consolidated Statements of Operations. All costs incurred prior to the transfer of control to the customer are included in gathering, transportation and processing expense in the Unaudited Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by the Company. If the Company's aggregate sales volumes for a well are greater (or less) than its proportionate share of production from the well, a liability (or receivable) is established to the extent there are insufficient proved reserves available to make-up the overproduced (or underproduced) imbalance. Imbalances have 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. A valuation allowance is recorded if it is more likely than not that all or some portion of the Company's deferred tax assets will not be realized. The Company regularly assesses the realizability of the deferred tax assets considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine if a valuation allowance is required. Changes to the Company's development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors 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 September 30, 2019.

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

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The dilutive net income per common share excludes the anti-dilutive effect of 3,107,116 nonvested shares of common stock for the three months ended September

9

30, 2019. The Company was in a net loss position for the nine months ended September 30, 2019 and the three and nine months ended September 30, 2018; therefore, all potentially dilutive securities were anti-dilutive.

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

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(in thousands, except per share amounts)
Net income (loss)	$	11,114	$	(29,360	)	$	(87,025	)	$	(101,203	)
Basic weighted-average common shares outstanding in period	210,550		209,502			210,288			181,145
Add dilutive effects of stock options and nonvested equity shares of common stock	387		—			—			—
Diluted weighted-average common shares outstanding in period	210,937		209,502			210,288			181,145
Basic net income (loss) per common share	$	0.05	$	(0.14	)	$	(0.41	)	$	(0.56	)
Diluted net income (loss) per common share	$	0.05	$	(0.14	)	$	(0.41	)	$	(0.56	)

New Accounting Pronouncements. In August 2018, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2018-13, Disclosure Framework-Changes to the Disclosure Requirements for Fair Value Measurement. The objective of this update is to improve the effectiveness of fair value measurement disclosures. ASU 2018-13 is effective for annual periods beginning after December 15, 2019 and interim periods within those annual periods. The standard will only impact the Company's disclosures.

In June 2018, the FASB issued ASU 2018-07, Stock Compensation-Improvements to Non-employee Share-Based Payment Accounting. The objective of this update was to simplify several aspects of the accounting for non-employee share-based payment transactions resulting from expanding the scope of Topic 718, Compensation- Stock Compensation, to include share-based payment transactions for acquiring goods and services from non-employees. ASU 2018-07 was effective for annual periods beginning after December 15, 2018, and interim periods within those annual periods. The standard was adopted on January 1, 2019 and did not have a material impact on the Company's disclosures and financial statements.

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

In February 2016, the FASB issued ASU 2016-02, Leases, followed by additional accounting standards updates that provided additional practical expedients and policy election options (collectively, Accounting Standards Codification Topic 842 ("ASC 842")). The objective of ASC 842 was to increase transparency and comparability among organizations by recognizing lease assets and lease liabilities on the balance sheet and requiring disclosure of key information about leasing arrangements. ASC 842 was effective for annual periods beginning after December 15, 2018 and interim periods within those annual periods. The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method and elected the option to not apply ASC 842 to comparative periods. The Company also elected the following practical expedients:

• not to recognize lease assets or liabilities on the balance sheet when lease terms are less than 12 months,

• carry forward previous conclusions related to current lease classification under the previous lease accounting standard to lease classification for these existing leases under ASC 842,

• exclude from evaluation under ASC 842 land easements that existed or expired before adoption of ASC 842, and

• to combine lease and non-lease components for certain asset classes.

The adoption of ASC 842 resulted in the recognition of right-of-use assets of $8.6 million, and current and noncurrent lease liabilities of $0.3 million and $13.7 million, respectively, on the Unaudited Consolidated Balance Sheet as of January 1, 2019. The difference between the right-of-use assets and the total lease liability was related to lease incentives and deferred rent balances of $5.4 million, which were required to be netted against the right-of-use assets as of the implementation date of

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January 1, 2019. The Company's leases included office leases and other equipment, all classified as operating leases. The adoption of ASC 842 had no impact on the Company's Unaudited Consolidated Statements of Operations or Cash Flows. See Note 11 for additional information.

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Nine Months Ended September 30,
	2019			2018
	(in thousands)
Cash paid for interest	$	29,168		$	25,746
Cash paid for income taxes	—			—
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases	970			—
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)	14,955			—
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties	44,970			101,838
Accrued liabilities - financing costs	—			215
Change in asset retirement obligations, net of disposals	(5,443		)	9,885
Retirement of treasury stock	(1,725		)	(1,533		)
Properties exchanged in non-cash transactions	4,561			—
Issuance of common stock for Merger	—			484,000

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

4. Divestiture and Merger

Divestiture

On May 1, 2019, the Company completed the sale of certain non-core assets, primarily low producing or shut-in vertical wells, in the DJ Basin in exchange for the relief of $7.7 million of plugging liabilities associated with these properties. The sale resulted in a loss of $2.3 million, which was recognized in loss on sale of properties in the Company's Unaudited Consolidated Statements of Operations.

2018 Merger with Fifth Creek Energy Operating Company, LLC

On March 19, 2018, the Company completed the Merger with Fifth Creek. The Merger was effected through the issuance of 100 million 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 million of Fifth Creek debt. In connection with the Merger, the Company incurred costs of $21.2 million relating to severance, consulting, advisory, legal and other merger-related fees, all of which were expensed and included in merger transaction expense in the Company's Unaudited Consolidated Statements of Operations.

Purchase Price Allocation

The transaction was accounted for as a business combination, using the acquisition method, with the Company being the acquirer for accounting purposes. The following table represents the allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed based on the estimated fair values at the acquisition date. The following table sets forth the Company's purchase price allocation:

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	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	25,782
Current unfavorable contract	2,651
Other current liabilities	13,797
Asset retirement obligations	7,361
Long-term deferred tax liability	137,707
Long-term unfavorable contract	4,449
Other noncurrent liabilities	2,354
Total purchase price plus liabilities assumed	$	732,001
Fair Value of Assets Acquired:
Cash	543
Accounts receivable	7,831
Oil and Gas Properties:
Proved oil and gas properties	105,702
Unproved oil and gas properties	609,568
Asset retirement obligations	7,361
Furniture, equipment and other	931
Other noncurrent assets	65
Total asset value	$	732,001

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 $20.9 million and $35.2 million from the Fifth Creek assets during the three and nine months ended September 30, 2018, respectively, and expenses of approximately $13.7 million and $25.1 million during the three and nine months ended September 30, 2018, respectively.

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 on January 1, 2018. 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.

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Additionally, pro forma earnings for the three months ended September 30, 2019 and September 30, 2018 were adjusted to exclude merger-related costs of $2.1 million and $0.1 million, respectively, incurred by the Company. Pro forma earnings for the nine months ended September 30, 2019 and 2018 were adjusted to exclude merger-related costs of $4.5 million and $6.1 million, respectively, incurred by the Company and 0 and $4.0 million, respectively, incurred by Fifth Creek. The pro forma results of operations do not include any cost savings or other synergies that may have occurred as a result of the acquisition or any estimated costs that have been incurred by the Company 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, 2018; furthermore, the financial information is not intended to be a projection of future results.

	Three Months Ended September 30,					Nine Months Ended September 30,
	2019		2018			2019			2018
	(in thousands, except per share data)
Revenues	$	121,282	$	131,126		$	330,846		$	338,266
Net Income (Loss) (1)	12,609		(29,260		)	(83,544		)	(98,993		)
Net Income (Loss) per Common Share, Basic (1)	0.06		(0.14		)	(0.40		)	(0.47		)
Net Income (Loss) per Common Share, Diluted (1)	0.06		(0.14		)	(0.40		)	(0.47		)

(1) The pro forma information for the three and nine months ended September 30, 2019 includes adjustments for merger-related costs of $2.1 million and $4.5 million, respectively.

5. Long-Term Debt

The Company's outstanding debt is summarized below:

 

		As of September 30, 2019							As of December 31, 2018
	Maturity Date	Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
		(in thousands)
Amended Credit Facility (1)	September 14, 2023	$	175,000	$	—		$	175,000	$	—	$	—		$	—
7.0% Senior Notes (2)	October 15, 2022	350,000		(2,582		)	347,418		350,000		(3,210		)	346,790
8.75% Senior Notes (3)	June 15, 2025	275,000		(3,888		)	271,112		275,000		(4,403		)	270,597
Lease Financing Obligation (4)	August 10, 2020	—		—			—		1,859		—			1,859
Total Debt		$	800,000	$	(6,470	)	$	793,530	$	626,859	$	(7,613	)	$	619,246
Less: Current Portion of Long-Term Debt (5)		—		—			—		1,859		—			1,859
Total Long-Term Debt		$	800,000	$	(6,470	)	$	793,530	$	625,000	$	(7,613	)	$	617,387

(1) The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure and on financing terms currently available to the Company.

(2) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $320.9 million and $329.7 million as of September 30, 2019 and December 31, 2018, respectively, based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $243.3 million and $264.7 million as of September 30, 2019 and December 31, 2018, respectively, based on reported market trades of these instruments.

(4) The aggregate estimated fair value of the Lease Financing Obligation was approximately $1.8 million as of December 31, 2018, based on market-based parameters of comparable term secured financing instruments. The Company exercised the early buyout option and purchased the equipment for $1.8 million on February 10, 2019.

(5) As of December 31, 2018, the current portion of long-term debt included the Lease Financing Obligation, which was settled on February 10, 2019.

Amended Credit Facility

The Company's revolving bank credit facility (the "Amended Credit Facility"), has a maturity date of September 14, 2023, a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing

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base of $500.0 million. The Company had $175.0 million and 0 outstanding under the Amended Credit Facility as of September 30, 2019 and December 31, 2018, respectively. As credit support for future payments under a contractual obligation, a $26.0 million letter of credit has been issued under the Amended Credit Facility, which reduced the available borrowing capacity under the Amended Credit Facility as of September 30, 2019 to $299.0 million.

Interest rates are either adjusted LIBOR plus applicable margins of 1.5% to 2.5% or an alternate base rate plus applicable margins of 0.5% to 1.5%, and the unused commitment fee is between 0.375% and 0.5%. The applicable margin and the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Amended Credit Facility was 4.1% for the three and nine months ended September 30, 2019.

Senior Notes

The issuer of the 7.0% Senior Notes and the 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett). Pursuant to supplemental indentures entered into in connection with the Merger, HighPoint Resources Corporation became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. All covenants in the indentures governing the notes limit the activities of HighPoint Operating Corporation, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to HighPoint Resources Corporation, but in most cases the covenants in the indentures are not applicable to HighPoint Resources Corporation. HighPoint Operating Corporation is currently in compliance with all covenants and has complied with all covenants since issuance.

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

Lease Financing Obligation Due 2020

The Company had a lease financing obligation with a balance of $1.9 million as of December 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 Company elected to exercise the early buyout option and purchased the equipment for $1.8 million on February 10, 2019.

6. Asset Retirement Obligations

A reconciliation of the Company's asset retirement obligations for the nine months ended September 30, 2019 is as follows (in thousands):

As of December 31, 2018	$	29,655
Liabilities incurred	2,835
Liabilities settled	(1,560		)
Disposition of properties (1)	(7,668		)
Accretion expense	1,174
Revisions to estimate	950
As of September 30, 2019	$	25,386
Less: Current asset retirement obligations	2,039
Long-term asset retirement obligations	$	23,347

(1) See additional information regarding disposition of properties in Note 4.

7. 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).

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

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

Level 3 – Pricing inputs include significant inputs that are generally less observable than objective sources. These inputs may be used with internally developed methodologies that result in management's best estimate of fair value. At each balance sheet date, the Company performs an analysis of all applicable instruments and includes in Level 3 all of those whose fair value is based on significant unobservable inputs.

Assets and Liabilities Measured at Fair Value on a Recurring Basis

Certain assets and liabilities are measured at fair value on a recurring basis in the Company's consolidated balance sheet. 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 costless collars are valued based on an income approach using various assumptions, such as quoted forward prices for commodities and time value factors. These assumptions are observable in the marketplace throughout the full term of the contract, can be derived from observable data or are supported by observable levels at which transactions are executed in the marketplace, and are, therefore, designated as Level 2 inputs. The Company utilizes its counterparties' valuations to assess the reasonableness of its own valuations. At times, the Company utilizes an independent third party to perform the valuation.

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

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

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	Level 1		Level 2		Level 3		Total
	(in thousands)
As of September 30, 2019
Financial Assets
Cash equivalents	$	—	$	—	$	—	$	—
Deferred compensation plan	1,778		—		—		1,778
Commodity derivatives	—		47,241		—		47,241
Financial Liabilities
Commodity derivatives	—		1,117		—		1,117
As of December 31, 2018
Financial Assets
Cash equivalents	$	12,188	$	—	$	—	$	12,188
Deferred compensation plan	1,392		—		—		1,392
Commodity derivatives	—		109,494		—		109,494
Financial Liabilities
Commodity derivatives	—		1,039		—		1,039

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Oil and gas properties – Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. 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. No properties were reduced to fair value during the three and nine month periods ended September 30, 2019 or 2018.

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 fair values of the Company's fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $564.2 million and $594.4 million as of September 30, 2019 and December 31, 2018, respectively. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of $175.0 million as of September 30, 2019 and 0 as of December 31, 2018. The fair value measurements for the Amended Credit Facility represent Level 2 inputs.

8. 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 contracts and costless collars related to the sale of a portion of the Company's production. 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

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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 September 30, 2019
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 (current)	$	37,218		$	(1,104	)	(1)	$	36,114
Derivative assets (noncurrent)	10,023			(13		)	(1)	10,010
Total derivative assets	$	47,241		$	(1,117	)		$	46,124
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(1,104	)	$	1,104		(1)	$	—
Other noncurrent liabilities	(13		)	13			(1)	—
Total derivative liabilities	$	(1,117	)	$	1,117			$	—
	As of December 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 (current)	$	82,205		$	(1,039	)	(1)	$	81,166
Derivative assets (noncurrent)	27,289			—			(1)	27,289
Total derivative assets	$	109,494		$	(1,039	)		$	108,455
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet				Net Amounts of Liabilities Presented in the Balance Sheet
	(in thousands)
Accounts payable and accrued liabilities	$	(1,039	)	$	1,039		(1)	$	—
Other noncurrent liabilities	—			—				—
Total derivative liabilities	$	(1,039	)	$	1,039			$	—

(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 September 30, 2019, the Company had swap contracts in place to hedge the following volumes for the periods indicated:

	October – December 2019			For the year 2020			For the year 2021
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,537,519	$	59.01	4,986,500	$	58.86	181,000	$	57.13
Natural Gas (MMbtu)	644,000	$	2.11	—	$	—	—	$	—

As of September 30, 2019, the Company had cashless collars (purchased put options and written call options) in place to hedge the following volumes for the periods indicated:

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	October – December 2019
	Derivative Volumes	Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls)	276,000	$	55.00	$	77.56

The Company's derivative financial instruments are generally executed with major financial or commodities trading institutions. The instruments expose the Company to market and credit risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company had derivatives in place with 10 different counterparties as of September 30, 2019. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

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

9. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB's rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three and nine months ended September 30, 2019 and 2018, the Company had no uncertain tax positions.

The Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three and nine months ended September 30, 2019 and 2018.

Income tax benefit for the three and nine months ended September 30, 2019 and 2018 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 2018, the effect of deferred tax asset valuation allowances. 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. NaN income tax expense or benefit was recognized for the three and nine months ended September 30, 2018 as a result of a full valuation allowance against the deferred tax asset balance. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.

10. 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

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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,
	2019			2018		2019		2018
	(in thousands)
Nonvested common stock (1)	$	1,992		$	1,654	$	5,321	$	4,504
Nonvested common stock units (1)	283			344		895		791
Nonvested performance cash units (2)(3)	(130		)	257		947		635
Total	$	2,145		$	2,255	$	7,163	$	5,930

(1) Unrecognized compensation expense as of September 30, 2019 was $7.5 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.7 years.

(2) The nonvested performance-based cash units are accounted for as liability awards with $1.3 million and $0.3 million in other noncurrent liabilities as of September 30, 2019 and December 31, 2018, respectively, in the Unaudited Consolidated Balance Sheets.

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

Nonvested Equity and Cash Awards. The following tables present the equity and cash awards granted pursuant to the Company's various stock compensation plans. A summary of the Company's nonvested common stock awards for the three and nine months ended September 30, 2019 and 2018 is presented below:

	Three Months Ended September 30, 2019				Three Months Ended September 30, 2018
Nonvested Common Stock Awards	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at July 1,	3,406,134		$	3.88	2,858,278		$	5.28
Granted	6,000		1.25		123,094		6.79
Vested	(356,009	)	4.19		(25,432	)	7.16
Forfeited or expired	(73,094	)	4.80		(38,292	)	5.34
Outstanding at September 30,	2,983,031		3.82		2,917,648		5.33
	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Nonvested Common Stock Awards	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value
Outstanding at January 1,	2,912,166		$	5.27	1,394,868		$	7.00
Granted	1,847,700		2.64		1,140,542		5.60
Modified (1)	—		—		1,146,305		4.84
Vested	(1,685,639	)	4.99		(693,364	)	8.24
Forfeited or expired	(91,196	)	4.83		(70,703	)	5.98
Outstanding at September 30,	2,983,031		3.82		2,917,648		5.33

(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 in nonvested common stock awards for the nine months ended September 30, 2018.

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

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	Three Months Ended September 30, 2019				Three Months Ended September 30, 2018
Nonvested Common Stock Unit Awards	Units		Weighted Average Grant Date Fair Value		Units		Weighted Average Grant Date Fair Value
Outstanding at July 1,	796,103		$	3.27	302,417		$	7.37
Granted	—		—		18,695		4.88
Vested	—		—		(18,695	)	4.88
Outstanding at September 30,	796,103		3.27		302,417		7.37
	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Nonvested Common Stock Unit Awards	Units		Weighted Average Grant Date Fair Value		Units		Weighted Average Grant Date Fair Value
Outstanding at January 1,	311,237		$	7.26	272,559		$	6.37
Granted	643,084		1.88		180,778		6.63
Vested	(158,218	)	5.44		(150,920	)	4.66
Outstanding at September 30,	796,103		3.27		302,417		7.37

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

	Three Months Ended September 30, 2019				Three Months Ended September 30, 2018
Nonvested Performance-Based Cash Unit Awards	Units		Weighted Average Fair Value		Units		Weighted Average Fair Value
Outstanding at July 1,	2,868,634				846,256
Granted	—				89,037
Forfeited or expired	(292,572	)			(16,232	)
Outstanding at September 30,	2,576,062		$	1.59	919,061		$	4.88
	Nine Months Ended September 30, 2019				Nine Months Ended September 30, 2018
Nonvested Performance-Based Cash Unit Awards	Units		Weighted Average Fair Value		Units		Weighted Average Fair Value
Outstanding at January 1,	909,585				1,548,083
Granted	2,026,521				935,293
Performance goal adjustment (1)	—				11,289
Modified (2)	—				(1,211,478	)
Vested	—				(286,652	)
Forfeited or expired	(360,044	)			(77,474	)
Outstanding at September 30,	2,576,062		$	1.59	919,061		$	4.88

(1) The 2015 Program vested at 104.1% in excess of target level and resulted in additional units vesting in March 2018. These units are included in the vested line item for the nine months ended September 30, 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 nine months ended September 30, 2018. The 2016 Program awards were converted based on 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.

Performance Cash Program

2019 Program. In February 2019, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the "2019 Program") granting performance cash units that will settle in cash and are accounted for

20

as liability awards. The performance-based awards contingently vest in February 2022, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2021, will be the Company's total shareholder return ("TSR") based on a matrix measurement of (1) the Company's absolute performance and (2) the Company's ranking relative to a defined peer group's individual TSRs ("Relative TSR"). The Company's absolute performance is measured against the December 31, 2018 closing share price of $2.49. For the portion of the program based on absolute performance (i) if the Company's absolute performance is less than 50%, the payout is 0, (ii) if the Company's absolute performance is 50%, the payout is 50% and (iii) if the Company's absolute performance is 100%, the payout is 100%, which is the maximum payout for this portion. For the portion of the program based on relative performance (i) if the Company's Relative TSR is less than 30%, the payout is 0 and (ii) if the Company's Relative TSR is 30% or greater, the payout is equal to the Company's percentile rank up to 100% of the original grant. The Company's combined absolute performance and Relative TSR have a maximum vest of up to 200% of the original grant.

11. Leases

The Company adopted ASC 842 effective January 1, 2019 using the modified retrospective method and elected the option to not apply ASC 842 to comparative periods. See Note 2 - New Accounting Pronouncements for the impacts of adopting this new standard.

Under ASC 842, a contract is or contains a lease when, (1) the contract contains an explicitly or implicitly identified asset and (2) the customer obtains substantially all of the economic benefits from the use of that underlying asset and directs how and for what purpose the asset is used during the term of the contract in exchange for consideration. The Company assesses whether an arrangement is or contains a lease at inception of the contract. For all leases, other than those that qualify for the short-term recognition exemption, the Company recognizes as of the lease commencement date on the balance sheet a liability for its obligation related to the lease and a corresponding asset representing the Company's right to use the underlying asset over the period of use. The Company currently has leases for office space and other equipment, all of which are classified as operating leases.

The Company's leases have remaining terms of up to nine years. Certain lease agreements contain options to extend or early terminate the agreement. These options are used to calculate right-of-use asset and lease liability balances when it is reasonably certain that the Company will exercise these options.

The discount rate used to calculate the present value of the future minimum lease payments is the rate implicit in the lease, when readily determinable. As most of the Company's leases do not provide an implicit rate, the Company utilizes its incremental borrowing rate.

The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, the Company recognizes the lease payments in the income statement on a straight-line basis over the lease term. The Company has also made the election, for certain classes of underlying assets, to combine lease and non-lease components. However, for the majority of its leases, the Company accounts for lease and non-lease components separately.

For the three and nine months ended September 30, 2019, lease cost was as follows:

	Three Months Ended September 30,		Nine Months Ended September 30,
Lease Cost	2019		2019
	(in thousands)
Operating lease cost (1)(3)	$	576	$	1,693
Short-term lease cost (2)(3)	2,678		13,064
Variable lease cost (4)	154		154
Total lease cost	$	3,408	$	14,911

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

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

21

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

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

Supplemental balance sheet information related to leases as of September 30, 2019, was as follows:

Operating Leases	As of September 30, 2019
	(in thousands)
Right-of-use assets (1)	$	9,475
Accumulated amortization (2)	(1,028		)
Total right-of-use assets, net (3)	$	8,447
Current lease liabilities (4)	(985		)
Noncurrent lease liabilities (5)	(13,598		)
Total lease liabilities (3)	$	(14,583	)
Weighted average remaining lease term
Operating leases (in years)	8.0
Weighted average discount rate
Operating leases	5.6		%

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

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

(3) The difference between the right-of-use assets and total lease liabilities is primarily related to lease incentives and deferred rent balances, which were required to be netted against the right-of-use assets as of the 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, 2019 were as follows:

	As of September 30, 2019
	(in thousands)
2019	$	342
2020	2,040
2021	2,340
2022	2,031
2023	2,024
Thereafter	9,654
Total	$	18,431
Less: Interest	(3,848		)
Present value of lease liabilities	$	14,583

Minimum future contractual payments for operating leases under the scope of ASC 840 as of December 31, 2018 were as follows:

22

	As of December 31, 2018
	(in thousands)
2019	$	2,583
2020	3,032
2021	3,331
2022	3,263
2023	3,036
Thereafter	13,112
Total	$	28,357

12. Commitments and Contingencies

Firm Transportation Agreements. The Company is party to 2 firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.

The Company is party to 1 firm pipeline transportation contract to provide capacity on an oil pipeline system. The contract requires the Company to pay minimum volume transportation charges from May 2020 through April 2025 regardless of the amount of pipeline capacity utilized by the Company.

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

	As of September 30, 2019
	(in thousands)
2019	$	4,544
2020	23,300
2021	19,797
2022	13,064
2023	14,600
Thereafter	19,440
Total	$	94,745

Gas Gathering and Processing Agreements. The Company is party to 1 minimum volume commitment and 1 reimbursement obligation. The minimum volume commitment requires the Company to deliver a minimum volume of natural gas to a midstream entity for gathering and processing. The contract requires the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The reimbursement obligation requires the Company to pay a monthly gathering and processing fee per Mcf of production to reimburse a midstream entity for its costs to construct gas gathering and processing facilities. If the costs are not reimbursed by the Company via the monthly gathering and processing fees, the Company must pay the difference. The amounts in the table below represent the Company's future minimum charges under both agreements:

	As of September 30, 2019
	(in thousands)
2019	$	2,291
2020	3,895
2021	1,997
Thereafter	—
Total	$	8,183

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Other Commitments. The Company is party to 1 minimum volume commitment for fresh water. The minimum volume commitment requires the Company to purchase a minimum volume of fresh water from a water supplier. The contract requires the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The Company also has non-cancellable agreements for information technology services. Future minimum annual payments under these agreements are as follows:

	As of September 30, 2019
	(in thousands)
2019	$	2,947
2020	1,490
2021	745
2022	745
2023	744
Thereafter	—
Total	$	6,671

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

13. Parent Guarantor

The condensed consolidating financial information as of and for the periods ended September 30, 2019 present the results of operations, financial position and cash flows of HighPoint Resources Corporation, or parent guarantor, HighPoint Operating Corporation (f/k/a Bill Barrett), or subsidiary issuer, and Fifth Pocket Production, LLC, a subsidiary guarantor (formed on August 1, 2019), 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, fully and unconditionally guarantee 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 to the formation of Fifth Pocket Production, LLC.

For the purpose of the following financial information, investments in subsidiaries are reflected in accordance with the equity method of accounting. The financial information may not necessarily be indicative of results of operations, cash flows, or financial position had the parent and the subsidiary operated as independent entities.

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Condensed Consolidating Balance Sheets

	As of September 30, 2019
	Parent Guarantor		Subsidiary Issuer		Subsidiary Guarantor (1)		Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	—	$	19,568	$	—	$	—		$	19,568
Accounts receivable, net of allowance for doubtful accounts	—		59,427		—		—			59,427
Other current assets	—		40,802		—		—			40,802
Property and equipment, net	—		2,127,989		—		—			2,127,989
Investment in subsidiaries	1,129,563		—		—		(1,129,563		)	—
Noncurrent assets	—		15,841		—		—			15,841
Total assets	$	1,129,563	$	2,263,627	$	—	$	(1,129,563	)	$	2,263,627
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities	$	—	$	88,524	$	—	$	—		$	88,524
Other current liabilities	—		97,084		—		—			97,084
Long-term debt	—		793,530		—		—			793,530
Deferred income taxes	—		114,263		—		—			114,263
Other noncurrent liabilities	—		40,663		—		—			40,663
Stockholders' equity	1,129,563		1,129,563		—		(1,129,563		)	1,129,563
Total liabilities and stockholders' equity	$	1,129,563	$	2,263,627	$	—	$	(1,129,563	)	$	2,263,627

(1) Subsidiary guarantor was formed on August 1, 2019 with an immaterial investment from the subsidiary issuer.

	As of December 31, 2018
	Parent Guarantor		Subsidiary Issuer		Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	—	$	32,774	$	—		$	32,774
Accounts receivable, net of allowance for doubtful accounts	—		72,943		—			72,943
Other current assets	—		84,064		—			84,064
Property and equipment, net	—		2,029,523		—			2,029,523
Investment in subsidiaries	1,212,098		—		(1,212,098		)	—
Noncurrent assets	—		33,156		—			33,156
Total assets	$	1,212,098	$	2,252,460	$	(1,212,098	)	$	2,252,460
Liabilities and Stockholders' Equity:
Accounts payable and other accrued liabilities	$	—	$	131,379	$	—		$	131,379
Other current liabilities	—		116,806		—			116,806
Long-term debt	—		617,387		—			617,387
Deferred income taxes	—		139,534		—			139,534
Other noncurrent liabilities	—		35,256		—			35,256
Stockholders' equity	1,212,098		1,212,098		(1,212,098		)	1,212,098
Total liabilities and stockholders' equity	$	1,212,098	$	2,252,460	$	(1,212,098	)	$	2,252,460

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Condensed Consolidating Statements of Operations 

	Three Months Ended September 30, 2019
	Parent Guarantor			Subsidiary Issuer			Subsidiary Guarantor (1)		Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	—		$	121,282		$	—	$	—		$	121,282
Operating expenses	—			(108,686		)	—		—			(108,686		)
General and administrative	—			(11,048		)	—		—			(11,048		)
Merger transaction expense	—			(2,078		)	—		—			(2,078		)
Interest expense	—			(15,167		)	—		—			(15,167		)
Interest income and other income (expense)	—			31,141			—		—			31,141
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	—			15,444			—		—			15,444
(Provision for) benefit from income taxes	—			(4,330		)	—		—			(4,330		)
Equity in earnings (loss) of subsidiaries	11,114			—			—		(11,114		)	—
Net income (loss)	$	11,114		$	11,114		$	—	$	(11,114	)	$	11,114
	Nine Months Ended September 30, 2019
	Parent Guarantor			Subsidiary Issuer			Subsidiary Guarantor (1)		Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	—		$	330,846		$	—	$	—		$	330,846
Operating expenses	—			(305,276		)	—		—			(305,276		)
General and administrative	—			(36,109		)	—		—			(36,109		)
Merger transaction expense	—			(4,492		)	—		—			(4,492		)
Interest expense	—			(43,227		)	—		—			(43,227		)
Interest income and other income (expense)	—			(54,038		)	—		—			(54,038		)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	—			(112,296		)	—		—			(112,296		)
(Provision for) benefit from income taxes	—			25,271			—		—			25,271
Equity in earnings (loss) of subsidiaries	(87,025		)	—			—		87,025			—
Net income (loss)	$	(87,025	)	$	(87,025	)	$	—	$	87,025		$	(87,025	)

(1) Subsidiary guarantor was formed on August 1, 2019 and did not generate any revenues or expenses for the three or nine months ended September 30, 2019.

26

	Three Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	—		$	131,126		$	—	$	131,126
Operating expenses	—			(83,172		)	—		(83,172		)
General and administrative	—			(12,696		)	—		(12,696		)
Merger transaction expense	—			(100		)	—		(100		)
Interest expense	—			(13,165		)	—		(13,165		)
Interest income and other income (expense)	—			(51,353		)	—		(51,353		)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	—			(29,360		)	—		(29,360		)
(Provision for) benefit from income taxes	—			—			—		—
Equity in earnings (loss) of subsidiaries	(29,360		)	—			29,360		—
Net income (loss)	$	(29,360	)	$	(29,360	)	$	29,360	$	(29,360	)
	Nine Months Ended September 30, 2018
	Parent Guarantor			Subsidiary Issuer			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	—		$	322,334		$	—	$	322,334
Operating expenses	—			(217,042		)	—		(217,042		)
General and administrative	—			(34,427		)	—		(34,427		)
Merger transaction expense	—			(6,140		)	—		(6,140		)
Interest expense	—			(39,348		)	—		(39,348		)
Interest income and other income (expense)	—			(126,580		)	—		(126,580		)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries	—			(101,203		)	—		(101,203		)
(Provision for) benefit from income taxes	—			—			—		—
Equity in earnings (loss) of subsidiaries	(101,203		)	—			101,203		—
Net income (loss)	$	(101,203	)	$	(101,203	)	$	101,203	$	(101,203	)

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Condensed Consolidating Statements of Cash Flows

	Nine Months Ended September 30, 2019
	Parent Guarantor		Subsidiary Issuer			Subsidiary Guarantor (1)		Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	—	$	195,394		$	—	$	—	$	195,394
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	—		(375,976		)	—		—		(375,976		)
Additions to furniture, fixtures and other	—		(3,958		)	—		—		(3,958		)
Proceeds from sale of properties	—		1,334			—		—		1,334
Other investing activities	—		(1,400		)	—				(1,400		)
Cash flows from financing activities:
Proceeds from debt	—		200,000			—		—		200,000
Principal payments on debt	—		(26,859		)	—		—		(26,859		)
Other financing activities	—		(1,741		)	—		—		(1,741		)
Change in cash and cash equivalents	—		(13,206		)	—		—		(13,206		)
Beginning cash and cash equivalents	—		32,774			—		—		32,774
Ending cash and cash equivalents	$	—	$	19,568		$	—	$	—	$	19,568

(1) Subsidiary guarantor was formed on August 1, 2019 and did not generate any cash flows for nine months ended September 30, 2019.

	Nine Months Ended September 30, 2018
	Parent Guarantor		Subsidiary Issuer			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	—	$	160,185		$	—	$	160,185
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions	—		(322,614		)	—		(322,614		)
Additions to furniture, fixtures and other	—		(616		)	—		(616		)
Payment of acquiree's debt associated with merger, net of cash acquired	—		(53,357		)	—		(53,357		)
Proceeds from sale of properties	—		(221		)	—		(221		)
Other investing activities	—		232			—		232
Cash flows from financing activities:
Principal payments on debt	—		(350		)	—		(350		)
Other financing activities	—		(4,745		)	—		(4,745		)
Change in cash and cash equivalents	—		(221,486		)	—		(221,486		)
Beginning cash and cash equivalents	—		314,466			—		314,466
Ending cash and cash equivalents	$	—	$	92,980		$	—	$	92,980

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

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

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

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

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

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

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

• derivative and hedging activities;

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

• compliance with environmental and other regulations;

• economic and competitive conditions;

• occurrence of property divestitures or acquisitions;

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

• future processing volumes and pipeline throughput;

• impact of health and safety issues on operations;

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

• 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 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, 2018 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" and in Part II, Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

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

Overview

29

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

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

Colorado Senate Bill 19-181 was signed into law on April 16, 2019, and took immediate effect. It authorizes local governments to approve the siting of and regulate the surface impacts from oil and natural gas facilities, and it empowers them to adopt requirements and impose conditions that are more stringent than state regulations. The statute changes the mission of the Colorado Oil and Gas Conservation Commission from fostering responsible and balanced development to regulating development to protect public health and the environment as the primary goal. It requires the Commission to undertake rulemaking on environmental protection, facility siting, cumulative impacts, flowline safety, orphan wells, financial assurance, wellbore integrity, and application fees. It also requires the Air Quality Control Commission to review its leak detection and repair regulations and adopt rules to further minimize emissions of hydrocarbons and nitrogen oxides. These rulemakings will impose new approval and operating requirements and may have an adverse effect on our development program, particularly in terms of costs and delays in the permitting process. However, we believe that the location of our assets in rural areas of Weld County, a jurisdiction generally supportive of oil and gas development, is likely to mitigate these impacts to a significant extent. 

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production 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 sale 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. As of October 21, 2019, we have hedged 1,813,519 barrels of oil and 644,000 MMbtu of natural gas, or approximately 52% of our expected remaining 2019 production, 5,032,500 barrels of oil for 2020 and 181,000 barrels of oil for 2021, at price levels that provide some economic certainty to our cash flows. We focus our efforts on increasing oil, natural gas and NGLs reserves and production while controlling costs at a level that is appropriate for long-term operations. Our future earnings and cash flows are dependent on our ability to manage our revenues and overall cost structure to a level that allows for profitable production.

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.

For the nine months ended September 30, 2018, as a result of the closing of the Merger on March 19, 2018, Fifth Creek's revenues and expenses are included in the Unaudited Consolidated Statement of Operations beginning on March 19, 2018.

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Results of Operations

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

Three Months Ended September 30, 2019 Compared with Three Months Ended September 30, 2018

	Three Months Ended September 30,					Increase (Decrease)
	2019		2018			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	121,281	$	131,585		$	(10,304	)	(8	)%
Other operating revenues	1		(459		)	460			*nm
Total operating revenues	121,282		131,126			(9,844		)	(8	)%
Operating Expenses
Lease operating expense	8,385		7,237			1,148			16	%
Gathering, transportation and processing expense	1,611		1,398			213			15	%
Production tax expense	7,868		11,504			(3,636		)	(32	)%
Exploration expense	56		19			37			195	%
Impairment, dry hole costs and abandonment expense	1,170		184			986			536	%
(Gain) loss on sale of properties	—		74			(74		)	(100	)%
Depreciation, depletion and amortization	84,948		58,946			26,002			44	%
Unused commitments	4,418		4,574			(156		)	(3	)%
General and administrative expense (1)	11,048		12,696			(1,648		)	(13	)%
Merger transaction expense	2,078		100			1,978			*nm
Other operating expense, net	230		(764		)	994			*nm
Total operating expenses	$	121,812	$	95,968		$	25,844		27	%
Production Data:
Oil (MBbls)	2,180		1,716			464			27	%
Natural gas (MMcf)	4,236		3,294			942			29	%
NGLs (MBbls)	513		471			42			9	%
Combined volumes (MBoe)	3,399		2,736			663			24	%
Daily combined volumes (Boe/d)	36,946		29,739			7,207			24	%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	52.27	$	66.96		$	(14.69	)	(22	)%
Natural gas (per Mcf)	1.03		1.59			(0.56		)	(35	)%
NGLs (per Bbl)	5.76		24.31			(18.55		)	(76	)%
Combined (per Boe)	35.68		48.10			(12.42		)	(26	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	54.08	$	55.92		$	(1.84	)	(3	)%
Natural gas (per Mcf)	1.06		1.64			(0.58		)	(35	)%
NGLs (per Bbl)	5.76		24.31			(18.55		)	(76	)%
Combined (per Boe)	36.88		41.23			(4.35		)	(11	)%
Average Costs (per Boe):
Lease operating expense	$	2.47	$	2.65		$	(0.18	)	(7	)%
Gathering, transportation and processing expense	0.47		0.51			(0.04		)	(8	)%
Production tax expense	2.31		4.20			(1.89		)	(45	)%
Depreciation, depletion and amortization	24.99		21.54			3.45			16	%
General and administrative expense (1)	3.25		4.64			(1.39		)	(30	)%

* Not meaningful.

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(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $2.1 million (or $0.63 per Boe) and $2.3 million (or $0.82 per Boe) for the three months ended September 30, 2019 and 2018, respectively.

Production Revenues and Volumes. Production revenues decreased to $121.3 million for the three months ended September 30, 2019 from $131.6 million for the three months ended September 30, 2018. The decrease in production revenues was due to a 26% decrease in average realized prices before hedging, offset by a 24% increase in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $34.0 million, while the increase in production volumes increased production revenues by approximately $23.7 million.

Lease Operating Expense ("LOE"). LOE decreased to $2.47 per Boe for the three months ended September 30, 2019 from $2.65 per Boe for the three months ended September 30, 2018. The decrease per Boe for the three months ended September 30, 2019 compared with the three months ended September 30, 2018 was due to a decrease in compressor maintenance and workovers.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense decreased to $0.47 per Boe for the three months ended September 30, 2019 from $0.51 per Boe for the three months ended September 30, 2018.

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

GTP expense for the three months ended September 30, 2019 of $0.47 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production mix from the Hereford Field under the existing contractual arrangement, with a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to $7.9 million for the three months ended September 30, 2019 from $11.5 million for the three months ended September 30, 2018. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 6.5% and 8.7% for the three months ended September 30, 2019 and September 30, 2018, respectively. The decrease in the rate for the three months ended September 30, 2019 was due to a decrease in our projected 2019 Colorado severance tax effective rate, based on updated information related to our annual 2019 severance tax return.

Depreciation, Depletion and Amortization ("DD&A"). DD&A increased to $84.9 million for the three months ended September 30, 2019 compared with $58.9 million for the three months ended September 30, 2018. The increase of $26.0 million was a result of a 24% increase in production volumes and a 16% increase in the DD&A rate for the three months ended September 30, 2019 compared with the three months ended September 30, 2018. The increase in production accounted for a $14.3 million increase in DD&A expense, while the increase in the DD&A rate accounted for an $11.7 million increase in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended September 30, 2019, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $24.99 per Boe compared with $21.54 per Boe for the three months ended September 30, 2018. The increase in the depletion rate of 16% is the result of year end 2018 reserve adjustments.

Unused Commitments. Unused commitments expense of $4.4 million and $4.6 million for the three months ended September 30, 2019 and September 30, 2018, respectively, 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.

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General and Administrative Expense. General and administrative expense decreased to $11.0 million for the three months ended September 30, 2019 from $12.7 million for the three months ended September 30, 2018. General and administrative expense on a Boe basis decreased to $3.25 for the three months ended September 30, 2019 from $4.64 for the three months ended September 30, 2018.

Included in general and administrative expense is long-term cash and equity incentive compensation of $2.1 million and $2.3 million for the three months ended September 30, 2019 and 2018, respectively. The components of long-term cash and equity incentive compensation for the three months ended September 30, 2019 and 2018 are shown in the following table:

	Three Months Ended September 30,
	2019			2018
	(in thousands)
Nonvested common stock	$	1,992		$	1,654
Nonvested common stock units	283			344
Nonvested performance cash units (1)	(130		)	257
Total	$	2,145		$	2,255

(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 and $0.1 million for the three months ended September 30, 2019 and September 30, 2018, respectively. Transaction expenses included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger.

Commodity Derivative Gain (Loss). Commodity derivative gain was $31.0 million for the three months ended September 30, 2019 compared with a loss of $51.5 million for the three months ended September 30, 2018. 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, 2019 and 2018 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 in the past 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,
	2019			2018
	(in thousands)
Realized gain (loss) on derivatives (1)	$	4,075		$	(18,780	)
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(20,739		)	4,920
Unrealized gain (loss) on derivatives (1)	47,711			(37,687		)
Total commodity derivative gain (loss)	$	31,047		$	(51,547	)

(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

33

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

During the three months ended 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 natural gas income of $0.1 million after settlements. During the three months ended September 30, 2018, approximately 74% of our oil volumes and 13% of our natural gas volumes were subject to financial hedges, which resulted in a decrease in oil income of $18.9 million and an increase in natural gas income of $0.1 million after settlements.

Income Tax (Expense) Benefit. For the three months ended September 30, 2019, income tax expense of $4.3 million was recognized. For the year ended December 31, 2018, we determined that it is more likely than not that we will 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 liabilities, assets acquired in connection with the Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. As a result of the analysis conducted, we reversed the majority of the valuation allowance on certain deferred tax assets. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets. No income tax expense or benefit was recognized for the three months ended September 30, 2018 as a result of a full valuation allowance against our deferred tax assets.

34

Nine Months Ended September 30, 2019 Compared with Nine Months Ended September 30, 2018

	Nine Months Ended September 30,					Increase (Decrease)
	2019		2018			Amount			Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production	$	330,472	$	322,534		$	7,938		2	%
Other operating revenues	374		(200		)	574			*nm
Total operating revenues	330,846		322,334			8,512			3	%
Operating Expenses
Lease operating expense	30,434		21,082			9,352			44	%
Gathering, transportation and processing expense	5,076		2,829			2,247			79	%
Production tax expense	20,666		26,363			(5,697		)	(22	)%
Exploration expense	93		39			54			138	%
Impairment, dry hole costs and abandonment expense	2,487		609			1,878			308	%
(Gain) loss on sale of properties	2,901		1,046			1,855			177	%
Depreciation, depletion and amortization	230,170		152,106			78,064			51	%
Unused commitments	13,239		13,684			(445		)	(3	)%
General and administrative expense (1)	36,109		34,427			1,682			5	%
Merger transaction expense	4,492		6,140			(1,648		)	(27	)%
Other operating expenses, net	210		(716		)	926			*nm
Total operating expenses	$	345,877	$	257,609		$	88,268		34	%
Production Data:
Oil (MBbls)	5,648		4,360			1,288			30	%
Natural gas (MMcf)	11,544		8,946			2,598			29	%
NGLs (MBbls)	1,466		1,207			259			21	%
Combined volumes (MBoe)	9,038		7,058			1,980			28	%
Daily combined volumes (Boe/d)	33,106		25,853			7,253			28	%
Average Realized Prices Before Hedging:
Oil (per Bbl)	$	52.82	$	64.61		$	(11.79	)	(18	)%
Natural gas (per Mcf)	1.58		1.59			(0.01		)	(1	)%
NGLs (per Bbl)	9.47		22.04			(12.57		)	(57	)%
Combined (per Boe)	36.57		45.70			(9.13		)	(20	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	54.31	$	54.70		$	(0.39	)	(1	)%
Natural gas (per Mcf)	1.52		1.65			(0.13		)	(8	)%
NGLs (per Bbl)	9.47		22.04			(12.57		)	(57	)%
Combined (per Boe)	37.42		39.66			(2.24		)	(6	)%
Average Costs (per Boe):
Lease operating expense	$	3.37	$	2.99		$	0.38		13	%
Gathering, transportation and processing expense	0.56		0.40			0.16			40	%
Production tax expense	2.29		3.74			(1.45		)	(39	)%
Depreciation, depletion and amortization	25.47		21.55			3.92			18	%
General and administrative expense (1)	4.00		4.88			(0.88		)	(18	)%

* Not meaningful.

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $7.2 million (or $0.79 per Boe) and $5.9 million (or $0.84 per Boe) for the nine months ended September 30, 2019 and 2018, respectively.

35

Production Revenues and Volumes. Production revenues increased to $330.5 million for the nine months ended September 30, 2019 from $322.5 million for the nine months ended September 30, 2018. The increase in production revenues was due to a 28% increase in production volumes, offset by a 20% decrease in average realized prices before hedging. The increase in production volumes increased production revenues by approximately $72.4 million, while average realized prices before hedging decreased production revenues by approximately $64.4 million.

Lease Operating Expense. LOE increased to $3.37 per Boe for the nine months ended September 30, 2019 from $2.99 per Boe for the nine months ended September 30, 2018. The increase per Boe for the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018 is primarily related to adverse weather impacting field operations in both the Northeast Wattenberg and Hereford fields during the three months ended March 31, 2019 and higher initial LOE related to our early development program in the Hereford field.

Gathering, Transportation and Processing Expense. GTP expense increased to $0.56 per Boe for the nine months ended September 30, 2019 from $0.40 per Boe for the nine months ended September 30, 2018.

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

GTP expense for the nine months ended September 30, 2019 of $0.56 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production mix from the Hereford Field under the existing contractual arrangement, with a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to $20.7 million for the nine months ended September 30, 2019 from $26.4 million for the nine months ended September 30, 2018. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Excluding the ad valorem and severance tax adjustments, production taxes as a percentage of oil, natural gas and NGL sales were 7.7% and 8.2% for the nine months ended September 30, 2019 and 2018, respectively. The decrease in the rate for the nine months ended September 30, 2019 was due to a decrease in our projected 2019 Colorado severance tax effective rate, based on updated information related to our annual 2019 severance tax return.

Depreciation, Depletion and Amortization. DD&A increased to $230.2 million for the nine months ended September 30, 2019 compared with $152.1 million for the nine months ended September 30, 2018. The increase of $78.1 million was a result of a 28% increase in production and an 18% increase in the DD&A rate for the nine months ended September 30, 2019 compared with the nine months ended September 30, 2018. The increase in production accounted for a $42.7 million increase in DD&A expense while the increase in the DD&A rate accounted for a $35.4 million increase in DD&A expense.

Under successful efforts accounting, depletion expense is calculated on a field-by-field basis based on geologic and reservoir delineation using the unit-of-production method. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the nine months ended September 30, 2019, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.47 per Boe compared with $21.55 per Boe for the nine months ended September 30, 2018. The increase in the depletion rate of 18% is the result of year end 2018 reserve adjustments.

Unused Commitments. Unused commitments expense of $13.2 million and $13.7 million for the nine months ended September 30, 2019 and 2018, respectively, 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 to $36.1 million for the nine months ended September 30, 2019 from $34.4 million for the nine months ended September 30, 2018. General and administrative

36

expense on a Boe basis decreased to $4.00 for the nine months ended September 30, 2019 from $4.88 for the nine months ended September 30, 2018.

Included in general and administrative expense is long-term cash and equity incentive compensation of $7.2 million and $5.9 million for the nine months ended September 30, 2019 and 2018, respectively. The components of long-term cash and equity incentive compensation for the nine months ended September 30, 2019 and 2018 are shown in the following table:

	Nine Months Ended September 30,
	2019		2018
	(in thousands)
Nonvested common stock	$	5,321	$	4,504
Nonvested common stock units	895		791
Nonvested performance cash units (1)	947		635
Total	$	7,163	$	5,930

(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 $4.5 million and $6.1 million for the nine months ended September 30, 2019 and September 30, 2018, respectively. Transaction expenses included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger.

Commodity Derivative Gain (Loss). Commodity derivative loss was $54.6 million for the nine months ended September 30, 2019 compared with a loss of $128.2 million for the nine months ended September 30, 2018. The loss for the nine months ended September 30, 2019 compared to the loss for the nine months ended September 30, 2018 was related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of September 30, 2019 and 2018 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 in the past 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,
	2019			2018
	(in thousands)
Realized gain (loss) on derivatives (1)	$	7,731		$	(42,628	)
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)	(61,430		)	20,940
Unrealized gain (loss) on derivatives (1)	(901		)	(106,478		)
Total commodity derivative gain (loss)	$	(54,600	)	$	(128,166	)

(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

37

understanding of our hedge position. We also believe that this disclosure allows for a more meaningful comparison to our peers.

During the nine months ended September 30, 2019, approximately 87% of our oil volumes and 22% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $8.4 million and a decrease in natural gas income of $0.7 million after settlements. During the nine months ended September 30, 2018, approximately 73% of our oil volumes and 15% of our natural gas volumes were subject to financial hedges, which resulted in a decrease in oil income of $43.2 million and an increase in natural gas income of $0.6 million after settlements.

Income Tax (Expense) Benefit. For the nine months ended September 30, 2019, income tax benefit of $25.3 million was recognized. For the year ended December 31, 2018, we determined that it was more likely than not that we would 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 liabilities, assets acquired in connection with the Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. As a result of the analysis conducted, we reversed a majority of the valuation allowance on certain deferred tax assets. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets. No income tax expense or benefit was recognized for the nine months ended September 30, 2018 as a result of a full valuation allowance against our deferred tax assets.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation have been net cash provided by operating activities, 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. 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 and under our Amended Credit Facility for our planned uses of capital for the remainder of 2019 and for 2020.

The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million, and an initial borrowing base of $500.0 million. On October 1, 2019, the commitment and borrowing base amounts were reaffirmed at $500.0 million. At December 31, 2018, we had cash and cash equivalents of $32.8 million and no amounts outstanding under the Amended Credit Facility. At September 30, 2019, we had cash and cash equivalents of $19.6 million and $175.0 million outstanding under the Amended Credit Facility. Our effective borrowing capacity as of September 30, 2019 was further reduced by $26.0 million to $299.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement.

Cash Flow from Operating Activities

Net cash provided by operating activities for the nine months ended September 30, 2019 and 2018 was $195.4 million and $160.2 million, respectively. The increase in net cash provided by operating activities was primarily due to an increase in cash settlements of derivatives.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors 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 contracts and cashless collars to receive fixed prices for a portion of our production. At September 30, 2019, we had in place crude oil swaps covering portions of our 2019, 2020, and 2021 production, natural gas swaps covering portions of our 2019 production and crude oil cashless collars covering portions of our 2019 production.

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The following table includes all hedges entered into through October 21, 2019.

Contract	Total Hedged Volumes	Quantity Type	Weighted Average Fixed Price		Weighted Average Floor Price		Weighted Average Ceiling Price		Index Price (1)
Swap Contracts:
2019
Oil	1,537,519	Bbls	$	59.01					WTI
Natural gas	644,000	MMBtu	$	2.11					NWPL
2020
Oil	5,032,500	Bbls	$	58.80					WTI
2021
Oil	181,000	Bbls	$	57.13					WTI
Cashless Collars:
2019
Oil	276,000	Bbls			$	55.00	$	77.56	WTI

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

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

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

Capital Expenditures

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

	Nine Months Ended September 30,
Basin/Area	2019		2018
	(in millions)
DJ Basin	$	321.9	$	380.6
Other	4.8		0.5
Total	$	326.7	$	381.1

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	Nine Months Ended September 30,
	2019		2018
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	4.3	$	8.3
Drilling, development, exploration and exploitation of oil and natural gas properties	294.9		342.8
Gathering and compression facilities	11.5		29.1
Geologic and geophysical costs	11.8		0.4
Furniture, fixtures and equipment	4.2		0.5
Total	$	326.7	$	381.1

Our current estimated capital expenditure budget for the quarter ended December 31, 2019 is $30.0 million to $40.0 million. The budget includes facilities costs and excludes acquisitions. We may 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 risk-adjusted 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 2019 and 2020 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

Amended Credit Facility. We had $175.0 million and zero outstanding under the Amended Credit Facility as of September 30, 2019 and December 31, 2018, respectively. The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million, and an initial borrowing base of $500.0 million. On October 1, 2019, the commitment and borrowing base amounts were reaffirmed at $500.0 million. Borrowing bases are computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices will generally result in a lower borrowing base.

We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2019 budget at current commodity prices.

Our outstanding debt is summarized below:

		As of September 30, 2019							As of December 31, 2018
	Maturity Date	Principal		Unamortized Discount			Carrying Amount		Principal		Unamortized Discount			Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	175,000	$	—		$	175,000	$	—	$	—		$	—
7.0% Senior Notes	October 15, 2022	350,000		(2,582		)	347,418		350,000		(3,210		)	346,790
8.75% Senior Notes	June 15, 2025	275,000		(3,888		)	271,112		275,000		(4,403		)	270,597
Lease Financing Obligation	August 10, 2020	—		—			—		1,859		—			1,859
Total Debt		$	800,000	$	(6,470	)	$	793,530	$	626,859	$	(7,613	)	$	619,246
Less: Current Portion of Long-Term Debt		—		—			—		1,859		—			1,859
Total Long-Term Debt (1)		$	800,000	$	(6,470	)	$	793,530	$	625,000	$	(7,613	)	$	617,387

(1) See Note 5 for additional information.

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

Contractual Obligations. A summary of our contractual obligations as of September 30, 2019 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, 2020		Twelve Months Ended September 30, 2021		Twelve Months Ended September 30, 2022		Twelve Months Ended September 30, 2023		Twelve Months Ended September 30, 2024		After September 30, 2024
	(in thousands)
Notes payable (1)	$	163	$	—	$	—	$	175,000	$	—	$	—	$	175,163
7.0% Senior Notes (2)	24,500		24,500		24,500		362,250		—		—		435,750
8.75% Senior Notes (3)	24,063		24,063		24,063		24,063		24,063		299,060		419,375
Firm transportation agreements (4)	21,404		23,735		11,886		14,600		14,640		8,480		94,745
Gas gathering and processing agreements (5)(6)	3,916		3,768		499		—		—		—		8,183
Asset retirement obligations (7)	2,039		2,037		2,000		2,006		2,210		15,094		25,386
Operating leases (8)	1,767		2,386		2,104		2,010		2,065		8,099		18,431
Other (9)	4,064		931		745		745		186		—		6,671
Total	$	81,916	$	81,420	$	65,797	$	580,674	$	43,164	$	330,733	$	1,183,704

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Also included in notes payable is interest on a $26.0 million letter of credit that accrues interest at 1.75% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term of the letter of credit is January 31, 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) We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the processing facility or pipeline.

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

(6) Includes a reimbursement obligation of $3.4 million. The reimbursement obligation requires us to pay a monthly gathering and processing fee per Mcf of production to reimburse a midstream entity for its 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.

(7) 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 HighPoint Resources' Annual Report on Form 10-K for the year ended December 31, 2018 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(8) 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.

(9) Primarily includes a fresh water commitment contract which requires us to purchase a minimum volume of fresh water from a supplier. The contract requires us to pay a fee associated with the contracted volumes regardless of the amount delivered.

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Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of September 30, 2019.

Trends and Uncertainties

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018 for a discussion of trends and uncertainties that may affect our financial condition or liquidity. Also see "Risk Factors" in Part II of this report.

Critical Accounting Policies and Estimates

We refer you to the corresponding section in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2018 and the notes to the Unaudited Consolidated Financial Statements included in Item 1 of this Quarterly Report on Form 10-Q for a description of critical accounting policies and estimates.

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

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 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 nine months ended September 30, 2019, our income before income taxes would have decreased by approximately $1.4 million for each $5.00 per barrel decrease in crude oil prices, approximately $0.9 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $1.3 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. 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.

As of October 21, 2019, we have swap contracts related to oil and natural gas volumes in place for the following periods indicated:

	October – December 2019			For the year 2020			For the year 2021
	Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price		Derivative Volumes	Weighted Average Price
Oil (Bbls)	1,537,519	$	59.01	5,032,500	$	58.80	181,000	$	57.13
Natural Gas (MMbtu)	644,000	$	2.11	—	$	—	—	$	—

As of October 21, 2019, we have cashless collars related to oil volumes in place for the following periods indicated:

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	October – December 2019
	Derivative Volumes	Weighted Average Floor Price		Weighted Average Ceiling Price
Oil (Bbls)	276,000	$	55.00	$	77.56

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

Interest Rate Risk

At September 30, 2019, we had $175.0 million outstanding under our Amended Credit Facility, which bears interest at floating rates. The weighted average annual interest rate incurred on this debt for the nine months ended September 30, 2019 was 4.1%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the nine months ended September 30, 2019 would have resulted in an estimated $0.9 million increase in interest expense assuming a similar average debt level to the nine months ended September 30, 2019. There were no borrowings under the Amended Credit Facility during 2018. 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, 2019.

Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of September 30, 2019, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the effectiveness of the design and operation of our disclosure controls and procedures pursuant to Rules 13a-15 and 15d-15 of the Securities Exchange Act of 1934. Based upon that evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures are effective as of September 30, 2019.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the third quarter of 2019 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 involved in various legal or governmental proceedings in the ordinary course of business. These proceeding are subject to the uncertainties inherent in any litigation. We review the status of these proceedings on an ongoing basis and, from time to time, may settle or otherwise resolve these matters on terms and conditions that management believes are in our best interests. While the ultimate outcome and impact of any proceeding cannot be predicted with certainty, our management does not believe that the resolution of any currently pending proceeding will have a material adverse effect on our financial condition or results of operations.

As previously disclosed, in the Annual Report on Form10-K for the year ended December 31, 2018, we received initial and supplemental EPA "Section 114" mandatory information directives, as well as parallel "compliance advisories" from the Colorado Department of Public Health and Environment ("CDPHE"). These directives led to settlement negotiations with EPA and CDPHE. In April 2019, we entered into a consent decree with the EPA and the CDPHE to resolve these matters. On June 24, 2019, the Court approved the consent decree, which required the Company to pay $275,000 to the United States and $55,000 to the State of Colorado, and fund a supplemental environmental project totaling $220,000, all of which have been fulfilled by the Company. Additionally, the Company has committed to undertake certain operational enhancements over the next three years.

Item 1A. Risk Factors.

Please refer to the "Risk Factors" section of our Annual Report on Form 10-K for the year ended December 31, 2018. An investment in our securities involves various risks. When considering an investment in our Company, you should carefully consider all of the risk factors described in our Annual Report on Form 10-K for the year ended December 31, 2018 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

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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, 2018 other than as detailed below.

If we cannot meet the "price criteria" for continued listing on 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.

If we do not maintain an average closing price of $1.00 or more for our common stock over any consecutive 30 trading-day period, the NYSE may delist our common stock for failure to maintain compliance with the NYSE price criteria listing standards. As of October 21, 2019, the average closing price of our common stock over the immediately preceding 30 consecutive trading-day period was $1.41. The NYSE Listed Company Manual sets out rules and processes to cure non-compliance with this standard. For instance, an issuer generally has six months to cure the listing standard related to stock price (such as a reverse-stock split), during which time the issuer's common stock would continue to be traded on the NYSE, subject to compliance with the other continued listing standards. A delisting of our common stock from the NYSE could negatively impact us because it could reduce the liquidity and market price of our common stock and reduce the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing, and/or diminish the value of equity incentives available to provide to our employees.

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

Unregistered Sales of Securities

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

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended September 30, 2019:

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
July 1 – 31, 2019	11,153	$	1.59	—	—
August 1 – 31, 2019	1,111	1.16		—	—
September 1 – 30, 2019	143,274	1.39		—	—
Total	155,538	1.40		—	—

(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.

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Item 6. Exhibits.

Exhibit Number	Description of Exhibits
31.1	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32.1	Section 1350 Certification of Chief Executive Officer.
32.2	Section 1350 Certification of Chief Financial Officer.
101.INS	Instance Document (The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.)
101.SCH	XBRL Taxonomy Extension Schema Document
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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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:	November 4, 2019	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President
			(Principal Executive Officer)
Date:	November 4, 2019	By:	/s/ David R. Macosko
			David R. Macosko
			Senior Vice President-Accounting
			(Principal Accounting Officer)

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