false2020Q10001725526December 310.0010.001400,000,000400,000,000215,064,108213,669,597215,064,108213,669,5973,531,8122,968,497——P3YP3Y00017255262020-01-012020-03-31xbrli:shares00017255262020-04-20iso4217:USD00017255262020-03-3100017255262019-12-31iso4217:USDxbrli:shares0001725526us-gaap:OilAndGasMember2020-01-012020-03-310001725526us-gaap:OilAndGasMember2019-01-012019-03-310001725526us-gaap:ProductAndServiceOtherMember2020-01-012020-03-310001725526us-gaap:ProductAndServiceOtherMember2019-01-012019-03-3100017255262019-01-012019-03-310001725526us-gaap:OilAndGasServiceMember2020-01-012020-03-310001725526us-gaap:OilAndGasServiceMember2019-01-012019-03-310001725526us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2020-01-012020-03-310001725526us-gaap:NaturalGasGatheringTransportationMarketingAndProcessingMember2019-01-012019-03-310001725526us-gaap:RetainedEarningsMember2020-01-012020-03-310001725526us-gaap:RetainedEarningsMember2019-01-012019-03-3100017255262018-12-3100017255262019-03-310001725526us-gaap:CommonStockMember2019-12-310001725526us-gaap:AdditionalPaidInCapitalMember2019-12-310001725526us-gaap:RetainedEarningsMember2019-12-310001725526us-gaap:TreasuryStockMember2019-12-310001725526us-gaap:CommonStockMember2020-01-012020-03-310001725526us-gaap:TreasuryStockMember2020-01-012020-03-310001725526us-gaap:AdditionalPaidInCapitalMember2020-01-012020-03-310001725526us-gaap:CommonStockMember2020-03-310001725526us-gaap:AdditionalPaidInCapitalMember2020-03-310001725526us-gaap:RetainedEarningsMember2020-03-310001725526us-gaap:TreasuryStockMember2020-03-310001725526us-gaap:CommonStockMember2018-12-310001725526us-gaap:AdditionalPaidInCapitalMember2018-12-310001725526us-gaap:RetainedEarningsMember2018-12-310001725526us-gaap:TreasuryStockMember2018-12-310001725526us-gaap:TreasuryStockMember2019-01-012019-03-310001725526us-gaap:AdditionalPaidInCapitalMember2019-01-012019-03-310001725526us-gaap:CommonStockMember2019-03-310001725526us-gaap:AdditionalPaidInCapitalMember2019-03-310001725526us-gaap:RetainedEarningsMember2019-03-310001725526us-gaap:TreasuryStockMember2019-03-310001725526hpr:AccruedOilAndNaturalGasSaleMember2020-03-310001725526hpr:AccruedOilAndNaturalGasSaleMember2019-12-310001725526us-gaap:CorporateJointVentureMember2020-03-310001725526us-gaap:CorporateJointVentureMember2019-12-310001725526hpr:OtherReceivablesMember2020-03-310001725526hpr:OtherReceivablesMember2019-12-310001725526hpr:ProvedOilAndGasPropertiesMember2020-01-012020-03-310001725526hpr:ProvedOilAndGasPropertiesMember2019-01-012019-03-310001725526hpr:UnprovedOilAndGasPropertiesMember2020-01-012020-03-310001725526hpr:UnprovedOilAndGasPropertiesMember2019-01-012019-03-310001725526srt:MinimumMember2020-01-012020-03-310001725526srt:MaximumMember2020-01-012020-03-310001725526hpr:AmendedCreditFacilityMember2020-01-012020-03-310001725526hpr:AmendedCreditFacilityMember2020-03-310001725526hpr:AmendedCreditFacilityMember2019-12-310001725526hpr:SevenPointZeroPercentageSeniorNotesMember2020-01-012020-03-310001725526hpr:SevenPointZeroPercentageSeniorNotesMember2020-03-310001725526hpr:SevenPointZeroPercentageSeniorNotesMember2019-12-310001725526hpr:EightPointSevenFivePercentageSeniorNotesMember2020-01-012020-03-310001725526hpr:EightPointSevenFivePercentageSeniorNotesMember2020-03-310001725526hpr:EightPointSevenFivePercentageSeniorNotesMember2019-12-31xbrli:pure0001725526srt:MinimumMember2020-03-310001725526srt:MaximumMember2020-03-310001725526us-gaap:FairValueInputsLevel1Member2020-03-310001725526us-gaap:FairValueInputsLevel2Member2020-03-310001725526us-gaap:FairValueInputsLevel3Member2020-03-310001725526us-gaap:EstimateOfFairValueFairValueDisclosureMember2020-03-310001725526us-gaap:FairValueInputsLevel1Member2019-12-310001725526us-gaap:FairValueInputsLevel2Member2019-12-310001725526us-gaap:FairValueInputsLevel3Member2019-12-310001725526us-gaap:EstimateOfFairValueFairValueDisclosureMember2019-12-310001725526hpr:ProvedOilAndGasPropertiesMemberus-gaap:FairValueInputsLevel3Member2020-03-310001725526hpr:UnprovedOilAndGasPropertiesMemberus-gaap:FairValueInputsLevel3Member2020-03-310001725526hpr:DerivativeAssetsMember2020-03-310001725526hpr:DerivativeAndOtherNonCurrentAssetsMember2020-03-310001725526hpr:DerivativeLiabilitiesMember2020-03-310001725526hpr:DerivativeAndOtherNonCurrentLiabilitiesMember2020-03-310001725526hpr:DerivativeAssetsMember2019-12-310001725526hpr:DerivativeAndOtherNonCurrentAssetsMember2019-12-310001725526hpr:DerivativeLiabilitiesMember2019-12-310001725526hpr:DerivativeAndOtherNonCurrentLiabilitiesMember2019-12-31utr:bbl0001725526srt:CrudeOilMemberhpr:HedgePeriodEndingCurrentYearMemberus-gaap:DerivativeSwapType2020-03-31iso4217:USDhpr:unit0001725526srt:CrudeOilMemberhpr:HedgePeriodEndingNextYearMemberus-gaap:DerivativeSwapType2020-03-310001725526hpr:HedgePeriodEndingInTwoYearsMembersrt:CrudeOilMemberus-gaap:DerivativeSwapType2020-03-310001725526us-gaap:SwaptionMemberhpr:HedgePeriodEndingCurrentYearMember2020-03-310001725526us-gaap:SwaptionMemberhpr:HedgePeriodEndingNextYearMember2020-03-310001725526us-gaap:SwaptionMemberhpr:HedgePeriodEndingInTwoYearsMember2020-03-31hpr:counterparty0001725526hpr:NonvestedEquityCommonStockUnitsMember2020-01-012020-03-310001725526hpr:CashBasedAwardMember2020-01-012020-03-310001725526hpr:NonvestedEquitySharesMember2020-01-012020-03-310001725526hpr:NonvestedEquitySharesMember2019-01-012019-03-310001725526hpr:NonvestedEquityCommonStockUnitsMember2019-01-012019-03-310001725526hpr:NonvestedPerformanceCashUnitsMember2020-01-012020-03-310001725526hpr:NonvestedPerformanceCashUnitsMember2019-01-012019-03-310001725526hpr:NonvestedPerformanceCashUnitsMember2020-03-310001725526hpr:NonvestedPerformanceCashUnitsMember2019-12-310001725526hpr:NonvestedEquitySharesMember2019-12-310001725526hpr:NonvestedEquitySharesMember2018-12-310001725526hpr:NonvestedEquitySharesMember2020-03-310001725526hpr:NonvestedEquitySharesMember2019-03-310001725526srt:DirectorMember2020-01-012020-03-310001725526srt:DirectorMember2019-12-310001725526srt:DirectorMember2018-12-310001725526srt:DirectorMember2019-01-012019-03-310001725526srt:DirectorMember2020-03-310001725526srt:DirectorMember2019-03-310001725526hpr:NonvestedPerformanceCashUnitsMember2018-12-310001725526hpr:NonvestedPerformanceCashUnitsMember2019-03-310001725526hpr:A2020ProgramMember2020-03-310001725526hpr:A2020ProgramMember2020-01-012020-03-310001725526hpr:A2020ProgramMemberhpr:AbsolutePerformanceandRelativeTSRMembersrt:MaximumMember2020-01-012020-03-31hpr:agreementhpr:integer

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 March 31, 2020

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

For the transition period from to

Commission file number 001-38435

HighPoint Resources Corporation
(Exact name of registrant as specified in its charter)

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

555 17th Street, Suite 3700
Denver, Colorado 80202
(Address of principal executive offices, including zip code)

(303) 293-9100
(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    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 215,064,108 shares of $0.001 par value common stock outstanding on April 20, 2020.

INDEX TO FINANCIAL STATEMENTS
 

3
PART I. FINANCIAL INFORMATION

Item 1. Consolidated Financial Statements.

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS
(UNAUDITED)

March 31, 2020 December 31, 2019
  (in thousands, except share data)
Assets:
Current Assets:
Cash and cash equivalents $ 11,203    $ 16,449   
Accounts receivable, net of allowance 53,595    62,120   
Derivative assets 126,207    3,916   
Prepayments and other current assets 2,709    3,952   
Total current assets 193,714    86,437   
Property and equipment - at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties 2,657,302    2,644,129   
Unproved oil and gas properties, excluded from amortization 315,216    357,793   
Furniture, equipment and other 29,943    29,804   
3,002,461    3,031,726   
Accumulated depreciation, depletion, amortization and impairment (2,210,712)   (967,552)  
Total property and equipment, net 791,749    2,064,174   
Derivative assets 35,979    —   
Other noncurrent assets 4,560    5,441   
Total $ 1,026,002    $ 2,156,052   
Liabilities and Stockholders' Equity:
Current Liabilities:
Accounts payable and accrued liabilities $ 100,253    $ 71,638   
Amounts payable to oil and gas property owners 44,004    37,922   
Production taxes payable 58,455    61,507   
Derivative liabilities —    4,411   
Total current liabilities 202,712    175,478   
Long-term debt, net of debt issuance costs 714,292    758,911   
Asset retirement obligations 23,407    23,491   
Deferred income taxes 2,137    97,418   
Other noncurrent liabilities 14,982    17,436   
Commitments and contingencies (Note 11)
Stockholders' Equity:
Common stock, $0.001 par value; authorized 400,000,000 shares; 215,064,108 and 213,669,597 shares issued and outstanding at March 31, 2020 and December 31, 2019, respectively, with 3,531,812 and 2,968,497 shares subject to restrictions, respectively 212    211   
Additional paid-in capital 1,778,571    1,777,779   
Retained earnings (accumulated deficit) (1,710,311)   (694,672)  
Treasury stock, at cost: zero shares at March 31, 2020 and December 31, 2019 —    —   
Total stockholders' equity 68,472    1,083,318   
Total $ 1,026,002    $ 2,156,052   

See notes to Unaudited Consolidated Financial Statements.
4
HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS
(UNAUDITED)
 
  Three Months Ended March 31,
  2020 2019
  (in thousands, except share and per share data)
Operating Revenues:
Oil, gas and NGL production $ 79,566    $ 101,705   
Other operating revenues, net —    275   
Total operating revenues 79,566    101,980   
Operating Expenses:
Lease operating expense 11,081    11,277   
Gathering, transportation and processing expense 4,412    1,723   
Production tax expense (2,508)   3,893   
Exploration expense 31    25   
Impairment and abandonment expense 1,265,426    322   
(Gain) loss on sale of properties —    (5)  
Depreciation, depletion and amortization 74,925    72,610   
Unused commitments 4,458    4,469   
General and administrative expense 10,215    12,660   
Merger transaction expense —    2,414   
Other operating expenses, net 55    (24)  
Total operating expenses 1,368,095    109,364   
Operating Income (Loss) (1,288,529)   (7,384)  
Other Income and Expense:
Interest and other income (expense) (195)   314   
Interest expense (14,383)   (13,679)  
Commodity derivative gain (loss) 192,188    (105,191)  
Total other income and expense 177,610    (118,556)  
Income (Loss) before Income Taxes (1,110,919)   (125,940)  
(Provision for) Benefit from Income Taxes 95,280    29,711   
Net Income (Loss) $ (1,015,639)   $ (96,229)  
Net Income (Loss) Per Common Share, Basic $ (4.81)   $ (0.46)  
Net Income (Loss) Per Common Share, Diluted $ (4.81)   $ (0.46)  
Weighted Average Common Shares Outstanding, Basic 211,111,830    209,931,744   
Weighted Average Common Shares Outstanding, Diluted 211,111,830    209,931,744   

See notes to Unaudited Consolidated Financial Statements.
5
HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS
(UNAUDITED)
 
  Three Months Ended March 31,
  2020 2019
  (in thousands)
Operating Activities:
Net Income (Loss) $ (1,015,639)   $ (96,229)  
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization 74,925    72,610   
Deferred income taxes (95,280)   (29,711)  
Impairment and abandonment expense 1,265,426    322   
Commodity derivative (gain) loss (192,188)   105,191   
Settlements of commodity derivatives 28,836    4,649   
Stock compensation and other non-cash charges 765    4,318   
Amortization of deferred financing costs 640    640   
(Gain) loss on sale of properties —    (5)  
Change in operating assets and liabilities:
Accounts receivable 8,524    15,470   
Prepayments and other assets 927    (72)  
Accounts payable, accrued and other liabilities (3,203)   7,304   
Amounts payable to oil and gas property owners 6,082    (10,906)  
Production taxes payable (3,052)   4,102   
Net cash provided by (used in) operating activities 76,763    77,683   
Investing Activities:
Additions to oil and gas properties, including acquisitions (39,210)   (130,862)  
Additions of furniture, equipment and other (474)   (1,309)  
Other investing activities 3,310    (273)  
Net cash provided by (used in) investing activities (36,374)   (132,444)  
Financing Activities:
Proceeds from debt 15,000    70,000   
Principal payments on debt (60,000)   (1,859)  
Other financing activities (635)   (1,496)  
Net cash provided by (used in) financing activities (45,635)   66,645   
Increase (Decrease) in Cash and Cash Equivalents (5,246)   11,884   
Beginning Cash and Cash Equivalents 16,449    32,774   
Ending Cash and Cash Equivalents $ 11,203    $ 44,658   

See notes to Unaudited Consolidated Financial Statements.
6
HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS' EQUITY
(UNAUDITED)
(In thousands)

Three Months Ended March 31, 2020 and 2019
Common
Stock 		Additional
Paid-In
Capital 		Retained
Earnings
(Accumulated
Deficit) 		Treasury
Stock 		Total
Stockholders'
Equity
Balance at December 31, 2019 $ 211    $ 1,777,779    $ (694,672)   $ —    $ 1,083,318   
Restricted stock activity and shares exchanged for tax withholding 1    —    —    (636)   (635)  
Stock-based compensation —    1,428    —    —    1,428   
Retirement of treasury stock —    (636)   —    636    —   
Net income (loss) —    —    (1,015,639)   —    (1,015,639)  
Balance at March 31, 2020 $ 212    $ 1,778,571    $ (1,710,311)   $ —    $ 68,472   
Balance at December 31, 2018 $ 210    $ 1,771,730    $ (559,842)   $ —    $ 1,212,098   
Restricted stock activity and shares exchanged for tax withholding —    —    —    (1,484)   (1,484)  
Stock-based compensation —    2,090    —    —    2,090   
Retirement of treasury stock —    (1,484)   —    1,484    —   
Net income (loss) —    —    (96,229)   —    (96,229)  
Balance at March 31, 2019 $ 210    $ 1,772,336    $ (656,071)   $ —    $ 1,116,475   

See notes to Unaudited Consolidated Financial Statements.
7
HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
(UNAUDITED)

March 31, 2020

1. Organization

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

2. Summary of Significant Accounting Policies

Basis of Presentation. The accompanying Unaudited Consolidated Financial Statements include the accounts of the Company. These statements have been prepared in accordance with accounting principles generally accepted in the United States of America ("GAAP"). All intercompany accounts and transactions have been eliminated in consolidation. In the opinion of management, the accompanying consolidated financial statements include all adjustments (consisting of normal recurring accruals and adjustments) necessary to present fairly, in all material respects, the Company's interim results. However, operating results for the periods presented are not necessarily indicative of the results that may be expected for the full year. The Company's Annual Report on Form 10-K for the year ended December 31, 2019 includes certain definitions and a summary of significant accounting policies and should be read in conjunction with this Quarterly Report on Form 10-Q. Except as disclosed herein, there have been no material changes to the information disclosed in the notes to the consolidated financial statements included in the Annual Report on Form 10-K.

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

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

Accounts Receivable. Accounts receivable is comprised of the following:

8
As of March 31, 2020 As of December 31, 2019
  (in thousands)
Oil, gas and NGL sales $ 34,977    $ 50,171   
Due from joint interest owners 16,762    9,551   
Other 1,877    2,419   
Allowance for doubtful accounts (21)   (21)  
Total accounts receivable $ 53,595    $ 62,120   

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 March 31, 2020 As of December 31, 2019
  (in thousands)
Proved properties $ 720,589    $ 725,964   
Wells and related equipment and facilities 1,822,838    1,805,136   
Support equipment and facilities 99,968    99,540   
Materials and supplies 13,907    13,489   
Total proved oil and gas properties $ 2,657,302    $ 2,644,129   
Unproved properties 188,168    265,387   
Wells and facilities in progress 127,048    92,406   
Total unproved oil and gas properties, excluded from amortization $ 315,216    $ 357,793   
Accumulated depreciation, depletion, amortization and impairment (2,200,820)   (958,475)  
Total oil and gas properties, net $ 771,698    $ 2,043,447   

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

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

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the "COVID-19 pandemic"). As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, the Organization of Petroleum Exporting Countries ("OPEC"), along with non-OPEC oil-producing countries (collectively knows as "OPEC+"), initiated discussions to lower production to support energy prices. By mid-March 2020, with OPEC+ unable to agree on cuts, crude oil prices declined to less than $25 per barrel, and have subsequently declined below $20 per barrel, compared to $59.80 at December 31, 2019. These events led to a decline in the recoverability of the carrying value of the Company's oil and gas properties. Since the carrying amount of the oil and gas properties was no longer recoverable, the Company impaired the carrying value to fair value. Therefore, the Company recognized non-cash impairment charges during the three months ended March 31, 2020, which were included within impairment and abandonment expense in the Unaudited Consolidated Statements of Operations.

9
For the three months ended March 31, 2020, the Company contracted with an independent third party to assist the Company in the Company's determination of fair value associated with the Company's proved and unproved oil and gas properties. Through the use of the Company's production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the proved developed producing ("PDP") and proved developed non-producing ("PDN") reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the proved undeveloped ("PUD"), probable ("PROB") and possible ("POSS") reserves. The Company's impairment and abandonment expense for the three months ended March 31, 2020 and 2019 is summarized below:

Three Months Ended March 31,
2020 2019
(in thousands)
Impairment of proved oil and gas properties $ 1,188,566    $ —   
Impairment of unproved oil and gas properties 76,298    —   
Abandonment expense 562    322   
Total impairment and abandonment expense $ 1,265,426    $ 322   

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

As of March 31, 2020 As of December 31, 2019
(in thousands)
Accrued drilling, completion and facility costs $ 51,613    $ 25,667   
Accrued lease operating, gathering, transportation and processing expenses 6,657    8,046   
Accrued general and administrative expenses 5,237    6,612   
Accrued interest payable 18,766    6,832   
Trade payables 11,502    17,488   
Operating lease liability 1,631    1,287   
Other 4,847    5,706   
Total accounts payable and accrued liabilities $ 100,253    $ 71,638   

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

Revenue Recognition. All of the Company's sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when the Company satisfies its performance obligations and the customer obtains control of the product. Performance obligations under the Company's contracts with customers are typically satisfied at a point-in-time through monthly delivery of oil, gas and/or NGLs. Accordingly, at the end of the reporting period, the Company does not have any unsatisfied performance obligations. The Company's contracts with customers typically include variable consideration based on monthly pricing tied to local indices and volumes delivered in the current month. The nature of the Company's contracts with customers does not require the Company to constrain variable consideration for accounting purposes. As of March 31, 2020, the Company had open contracts with customers with terms of 1 month to 18 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
10
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 including changes in tax law could change the valuation allowance in future periods, resulting in recognition of a tax expense or benefit.

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. Only tax positions that meet the more-likely-than-not recognition threshold are recognized. The Company does not have any uncertain tax positions recorded as of March 31, 2020.

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

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The Company was in a net loss position for both the three months ended March 31, 2020 and 2019; therefore, all potentially dilutive securities were anti-dilutive.

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

  Three Months Ended March 31,
  2020 2019
(in thousands, except per share amounts)
Net income (loss) $ (1,015,639)   $ (96,229)  
Basic weighted-average common shares outstanding in period
211,112    209,932   
Diluted weighted-average common shares outstanding in period
211,112    209,932   
Basic net income (loss) per common share $ (4.81)   $ (0.46)  
Diluted net income (loss) per common share $ (4.81)   $ (0.46)  

New Accounting Pronouncements. In April 2020, the Financial Accounting Standards Board ("FASB") issued Accounting Standards Update ("ASU") 2020-04, Facilitation of the Effects of Reference Rate Reform on Financial Reporting. In response to the cessation of the London Interbank Offered Rate ("LIBOR") by December 31, 2022, the FASB issued this update to provide optional expedients and exceptions for applying GAAP to contracts, hedging relationships, and other affected transactions. The Company currently has only one contract, its credit facility, that may be impacted by this ASU. Modifications
11
of debt contracts should be accounted for by prospectively adjusting the effective interest rate. This update is effective as of March 12, 2020 through December 31, 2022 and allows for elections to be made by the Company in terms of how the ASU is adopted. Once elected for a Topic or Industry Subtopic, the update must be applied prospectively for all eligible contract modifications for that Topic or Industry Subtopic. The Company does not believe the standard will have a material impact on the Company's financial statements.

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

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

3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

  Three Months Ended March 31,
  2020 2019
(in thousands)
Cash paid for interest $ 1,810    $ 868   
Cash paid for income taxes —    —   
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases 311    229   
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)(2)
112    14,667   
Non-cash investing and financing activities:
Accounts payable and accrued liabilities - oil and gas properties 58,384    92,702   
Change in asset retirement obligations, net of disposals (380)   933   
Retirement of treasury stock (636)   (1,484)  

(1)Excludes the reclassifications of lease incentives and deferred rent balances.
(2)The three months ended March 31, 2019 included $14.0 million of right-of-use assets established with the adoption of ASC 842, Leases, effective January 1, 2019.

4. Long-Term Debt

The Company's outstanding debt is summarized below:
 
    As of March 31, 2020 As of December 31, 2019
  Maturity Date Principal Debt Issuance Costs Carrying
Amount 		Principal Debt Issuance Costs Carrying
Amount
(in thousands)
Amended Credit Facility September 14, 2023 $ 95,000    $ —    $ 95,000    $ 140,000    $ —    $ 140,000   
7.0% Senior Notes October 15, 2022 350,000    (2,163)   347,837    350,000    (2,372)   347,628   
8.75% Senior Notes June 15, 2025 275,000    (3,545)   271,455    275,000    (3,717)   271,283   
Total Long-Term Debt $ 720,000    $ (5,708)   $ 714,292    $ 765,000    $ (6,089)   $ 758,911   
12
Amended Credit Facility

The Company's revolving bank credit facility (the "Amended Credit Facility"), has a maximum commitment amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing base of $500.0 million. The Company had $95.0 million and $140.0 million outstanding under the Amended Credit Facility as of March 31, 2020 and December 31, 2019, 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 March 31, 2020 to $379.0 million. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if the Company has more than $100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because the Company's 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

Interest rates on outstanding loans under the Amended Credit Facility 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 margins and the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Amended Credit Facility was 3.4% and 4.0% for the three months ended March 31, 2020 and 2019, respectively.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from the reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt. The Company is in the process of its semi-annual borrowing base redetermination and expects to finalize it by mid-May. As a result of current market conditions, the Company expects its borrowing capacity could be reduced by an amount up to 50% and may include higher LIBOR margin pricing.

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

Senior Notes

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

13
Nothing in the indentures governing the 7.0% Senior Notes or the 8.75% Senior Notes prohibits the Company from repurchasing any of the notes from time to time at any price in open market purchases, negotiated transactions or by tender offer or otherwise without any notice to or consent of the holders.

5. Asset Retirement Obligations

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

As of December 31, 2019 $ 25,709   
Liabilities incurred 165   
Liabilities settled (510)  
Disposition of properties (143)  
Accretion expense 429   
Revisions to estimate 108   
As of March 31, 2020 $ 25,758   
Less: Current asset retirement obligations 2,351   
Long-term asset retirement obligations $ 23,407   

6. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

Deferred compensation plan – The Company maintains a non-qualified deferred compensation plan which allows certain management employees to defer receipt of a portion of their compensation. The Company maintains assets for the deferred compensation plan in a rabbi trust. The assets of the rabbi trust are invested in publicly traded mutual funds and are recorded in
14
other current and other long-term assets in the Unaudited Consolidated Balance Sheets. The deferred compensation plan financial assets are reported at fair value based on active market quotes, which represent Level 1 inputs.

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

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

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

Level 1 Level 2 Level 3 Total
  (in thousands)
As of March 31, 2020
Financial Assets
Deferred compensation plan $ 1,047    $ —    $ —    $ 1,047   
Commodity derivatives —    163,461    —    163,461   
Financial Liabilities
Commodity derivatives —    1,275    —    1,275   
As of December 31, 2019
Financial Assets
Deferred compensation plan $ 2,033    $ —    $ —    $ 2,033   
Commodity derivatives —    8,890    —    8,890   
Financial Liabilities
Commodity derivatives —    10,056    —    10,056   

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Oil and gas properties – Proved oil and natural gas properties are evaluated for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever the Company concludes the carrying value may not be recoverable, the Company estimates the expected undiscounted future net cash flows of its oil and gas properties using proved and risked probable and possible reserves based on its development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future net revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. During the three months ended March 31, 2020, the Company's proved oil and gas properties with a carrying value of $1.7 billion were reduced to a fair value of $0.5 billion, resulting in an impairment of $1.2 billion which was included in impairment and abandonment expense on the Unaudited Statement of Operations for the three months ended March 31, 2020. For the three months ended March 31, 2020, the Company contracted with an independent third party to assist with the
15
Company's determination of fair value associated with its proved oil and gas properties. Through the use of the Company's production and price forecast, the third party used the income valuation technique to assist the Company in the determination of fair value for the PDP and PDN reserves and a market approach utilizing sales prices of comparable properties to assist the Company in the determination of fair value of the PUD reserves. The following table includes quantitative information about the significant unobservable inputs, categorized within Level 3 of the fair value hierarchy, that were used in the fair value measurement.

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

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

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

Additional Fair Value Disclosures

Long-term Debt – Long-term debt is not presented at fair value on the Unaudited Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The estimated fair value of the 7.0% Senior Notes was approximately $182.2 million and $335.0 million as of March 31, 2020 and December 31, 2019, respectively. The estimated fair value of the 8.75% Senior Notes was approximately $132.0 million and $251.2 million as of March 31, 2020 and December 31, 2019, respectively. The fair values of the Company's fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility. The recorded value of the Amended Credit Facility is not materially different from its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company's borrowing base utilization. The Amended Credit Facility had a balance of $95.0 million as of March 31, 2020 and $140.0 million as of December 31, 2019. The fair value measurements for the Amended Credit Facility represent Level 2 inputs.

7. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap and swaption contracts related to the sale of a portion of the Company's production. A swap allows the Company to receive a fixed price for its production and pay a variable market price to the counterparty. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. The Company 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
16
financial impact of physical commodity contracts is included in oil, natural gas and NGL production revenues at the time of settlement.

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

As of March 31, 2020
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) $ 126,207    $ —    $ 126,207   
Derivative assets (noncurrent) 37,254    (1,275)  
(1)
35,979   
Total derivative assets $ 163,461    $ (1,275)   $ 162,186   
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 $ —    $ —    $ —   
Other noncurrent liabilities (1,275)   1,275   
(1)
—   
Total derivative liabilities $ (1,275)   $ 1,275    $ —   
  
As of December 31, 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) $ 8,477    $ (4,561)  
(1)
$ 3,916   
Derivative assets (noncurrent) 413    (413)  
(1)
—   
Total derivative assets $ 8,890    $ (4,974)   $ 3,916   
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 $ (8,972)   $ 4,561   
(1)
$ (4,411)  
Other noncurrent liabilities (1,084)   413   
(1)
(671)  
Total derivative liabilities $ (10,056)   $ 4,974       $ (5,082)  
 
(1)Asset and liability balances with the same counterparty are presented as a net asset or liability on the Unaudited Consolidated Balance Sheets.

As of March 31, 2020, the Company had swap and swaption contracts in place to hedge the following volumes for the periods indicated:

April – December 2020 For the year 2021 For the year 2022
Derivative
Volumes 		Weighted Average Price Derivative Volumes Weighted Average Price Derivative Volumes Weighted Average Price
Swaps
Oil (Bbls) 4,034,000    $ 57.48    3,007,500    $ 54.71    —    $ —   
Swaptions
Oil (Bbls) —    $ —    —    $ —    1,092,000    $ 55.08   

17
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 nine different counterparties as of March 31, 2020. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

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

8. Income Taxes

The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return in accordance with the FASB's rules on income taxes. The Company recognizes the tax benefit from an uncertain tax position only if it is more likely than not that the tax position will be sustained upon examination by the taxing authorities. During the three months ended March 31, 2020 and 2019, the Company had no uncertain tax positions.

The Company's policy is to classify accrued penalties and interest related to unrecognized tax benefits in the Company's income tax provision. The Company did not record any accrued interest or penalties associated with unrecognized tax benefits during the three months ended March 31, 2020 and 2019.

Income tax benefit for the three months ended March 31, 2020 and 2019 differs from the amounts that would be provided by applying the U.S. statutory income tax rates to pretax income or loss principally due to stock-based compensation, political lobbying expense, political contributions, nondeductible officer compensation, state income taxes, and for 2020, the effect of deferred tax asset valuation allowances. For the three months ended March 31, 2020 and 2019, the Company recognized $95.3 million and $29.7 million of income tax benefit, respectively. The Company considers all available evidence (both positive and negative) to estimate whether sufficient future taxable income will be generated to permit the use of the existing deferred tax assets. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. For the three months ended March 31, 2020, the Company determined that there would not be sufficient future taxable income to use existing deferred tax assets and has recorded a valuation allowance against the existing net deferred tax assets. For the three months ended March 31, 2020, the Company has recorded a deferred tax liability of $2.1 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. The Company continues to monitor facts and circumstances in the reassessment of the likelihood that operating loss carryforwards, credits and other deferred tax assets will be utilized prior to their expiration.

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

18
9. Equity Incentive Compensation Plans and Other Long-term Incentive Programs

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

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

  Three Months Ended March 31,
  2020 2019
  (in thousands)
Nonvested common stock (1)
$ 1,150    $ 1,796   
Nonvested common stock units (1)
280    294   
Nonvested performance cash units (2)(3)
(974)   632   
Total $ 456    $ 2,722   

(1)Unrecognized compensation expense as of March 31, 2020 was $6.8 million, which related to grants of nonvested shares of common stock that are expected to be recognized over a weighted-average period of 1.9 years.
(2)The nonvested performance-based cash units are accounted for as liability awards with $0.2 million and $1.2 million in other noncurrent liabilities as of March 31, 2020 and December 31, 2019, respectively, in the Unaudited Consolidated Balance Sheets.
(3)Liability awards are fair valued at each reporting date. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date.

Nonvested Equity and Cash Awards. The following tables present the equity and cash awards granted pursuant to the Company's various stock compensation plans. A summary of the Company's nonvested common stock awards for the three months ended March 31, 2020 and 2019 is presented below:

Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Nonvested Common Stock Awards Shares Weighted Average
Grant Date
Fair Value 		Shares Weighted Average
Grant Date
Fair Value
Outstanding at January 1, 2,968,497    $ 3.81    2,912,166    $ 5.27   
Granted 2,028,617    1.14    1,835,700    2.64   
Vested (1,455,814)   4.25    (1,299,599)   5.19   
Forfeited or expired (9,488)   3.44    (16,487)   4.74   
Outstanding at March 31, 3,531,812    2.10    3,431,780    3.90   
A summary of the Company's nonvested common stock unit awards for the three months ended March 31, 2020 and 2019 is presented below:

Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Nonvested Common Stock Unit Awards Units Weighted Average
Grant Date
Fair Value 		Units Weighted Average
Grant Date
Fair Value
Outstanding at January 1, 796,103    $ 3.27    311,237    $ 7.26   
Granted —    —    14,704    2.21   
Vested —    —    (14,704)   2.21   
Outstanding at March 31, 796,103    3.27    311,237    7.26   

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

19
Three Months Ended March 31, 2020 Three Months Ended March 31, 2019
Nonvested Performance-Based Cash Unit Awards Units Weighted Average
Fair Value 		Units Weighted Average
Fair Value
Outstanding at January 1, 2,576,062    909,585   
Granted 3,569,434    2,026,521   
Forfeited or expired (49,266)   (67,472)  
Outstanding at March 31, 6,096,230    $ 0.19    2,868,634    $ 2.21   

Performance Cash Program

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

10. Leases

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

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

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

For the three months ended March 31, 2020 and 2019, lease cost were as follows:

  Three Months Ended March 31,
Lease Cost 2020 2019
(in thousands)
Operating lease cost (1)(3)
$ 510    $ 548   
Short-term lease cost (2)(3)
2,263    6,219   
Variable lease cost (4)
320    —   
Total lease cost $ 3,093    $ 6,767   

20
(1)Operating lease cost was primarily included in general and administrative expense or lease operating expense on the Unaudited Consolidated Statements of Operations.
(2)Short-term lease cost primarily includes leases for drilling rigs, which were capitalized to property, plant and equipment on the Unaudited Consolidated Balance Sheets.
(3)A portion of the operating lease cost and a majority of the short-term lease cost represent gross amounts that the Company was financially committed to pay. However, the Company recorded in the financial statements its proportionate share based on the Company's working interest, which varies from property to property.
(4)Variable lease cost is related to a gathering agreement and is included in oil, gas, and NGL production on the Unaudited Consolidated Statements of Operations.

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

Operating Leases As of March 31, 2020 As of December 31, 2019
(in thousands)
Right-of-use assets (1)
$ 9,268    $ 9,287   
Accumulated amortization (2)
(1,323)   (1,142)  
Total right-of-use assets, net (3)
$ 7,945    $ 8,145   
Current lease liabilities (4)
(1,631)   (1,287)  
Noncurrent lease liabilities (5)
(12,851)   (13,195)  
Total lease liabilities (3)
$ (14,482)   $ (14,482)  
Weighted average remaining lease term
Operating leases (in years) 7.6 7.8
Weighted average discount rate
Operating leases 5.6  % 5.6  %

(1)Included in furniture, equipment and other in the Unaudited Consolidated Balance Sheets.
(2)Included in accumulated depreciation, depletion, amortization and impairment in the Unaudited Consolidated Balance Sheets.
(3)The difference between the right-of-use assets and total lease liabilities is primarily related to lease incentives and deferred rent balances, which were required to be netted against the right-of-use assets as of the ASC 842 implementation date of January 1, 2019.
(4)Included in accounts payable and accrued liabilities in the Unaudited Consolidated Balance Sheets.
(5)Included in other noncurrent liabilities in the Unaudited Consolidated Balance Sheets.

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

As of March 31, 2020 As of December 31, 2019
  (in thousands)
2020 $ 1,777    $ 2,056   
2021 2,398    2,355   
2022 2,087    2,044   
2023 2,027    2,024   
2024 2,078    2,078   
Thereafter 7,576    7,577   
Total $ 17,943    $ 18,134   
Less: Interest (3,461)   (3,652)  
Present value of lease liabilities $ 14,482    $ 14,482   

11. Commitments and Contingencies

Firm Transportation Agreements. The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are
21
included in unused commitments expense in the Unaudited Consolidated Statements of Operations. As a result of previous divestitures in 2013 and 2014, the Company will likely not utilize the firm capacity on the natural gas pipelines.

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

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

As of March 31, 2020
  (in thousands)
2020 $ 18,641   
2021 19,778   
2022 13,064   
2023 14,600   
2024 14,640   
Thereafter 4,800   
Total $ 85,523   

Gas Gathering and Processing Agreements. The Company is party to one minimum volume commitment and one 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 March 31, 2020
  (in thousands)
2020 $ 1,981   
2021 1,996   
Thereafter —   
Total $ 3,977   

Other Commitments. The Company is party to one 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 March 31, 2020
(in thousands)
2020 $ 805   
2021 805   
2022 805   
2023 745   
Thereafter —   
Total $ 3,160   

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.
22
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations.

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

•outbreaks of communicable diseases like COVID-19 and resulting regulatory and economic consequences;
•the ability and willingness of members of the Organization of Petroleum Exporting Countries ("OPEC") along with non-OPEC oil-producing countries (collectively knows as "OPEC+"), to agree to and maintain oil price and production controls;
•debt and equity market conditions and availability of capital;
•reductions in the borrowing base under our amended revolving credit facility (the "Amended Credit Facility");
•any failure to comply with the financial or other covenants under our Amended Credit Facility, which could result in an event of default that could raise substantial doubt about our ability to continue as a going concern;
•downstream shut-ins due to oversupply and shortage of storage capacity;
•legislative, judicial or regulatory changes including initiatives to impose increased setbacks from occupied structures and other sensitive areas, initiatives to give local governmental authorities the ability to further regulate or to ban oil and gas development activities within their boundaries, and initiatives related to drilling and completion techniques such as hydraulic fracturing;
•potential failure to achieve expected production from existing and future exploration or development projects or acquisitions;
•volatility of market prices received for oil, natural gas and natural gas liquids ("NGLs"), and the risk of a prolonged period of depressed prices;
•declines in the values of our oil and natural gas properties resulting in impairments;
•reduction of proved undeveloped reserves due to failure to develop within the five-year development window defined by the Securities and Exchange Commission;
•derivative and hedging activities;
•the concentration of our properties in the Rocky Mountain region;
•compliance with environmental and other regulations;
•economic and competitive conditions;
•occurrence of property divestitures or acquisitions;
•costs and availability of third party facilities for gathering, processing, refining and transportation;
•future processing volumes and pipeline throughput;
•impact of health and safety issues on operations;
•operational risks, including the risk of industrial accidents and natural disasters;
•ability to receive drilling and other permits, regulatory approvals and required surface access and rights of way;
•higher than expected costs and expenses including production, drilling and well equipment costs;
•changes in estimates of proved reserves;
•the potential for production decline rates from our wells, and/or drilling and related costs, to be greater than we expect;
•ability to replace natural production declines with acquisitions, new drilling or recompletion activities;
•exploration risks such as the risk of drilling unsuccessful wells;
•capital expenditures and contractual obligations;
•liabilities resulting from litigation concerning alleged damages related to environmental issues, pollution, contamination, personal injury, royalties, marketing, title to properties, validity of leases, or other matters that may not be covered by an effective indemnity or insurance;
•midstream capacity issues;
•changes in tax laws and statutory tax rates; and
•other uncertainties, including those factors discussed below and in our Annual Report on Form 10-K for the year ended December 31, 2019 under the headings "Cautionary Note Regarding Forward-Looking Statements" and "Risk Factors" and in Part II, Item 1A, "Risk Factors" of this Quarterly Report on Form 10-Q, all of which are difficult to predict.

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.
23
Other than as required under the securities laws, we do not undertake any obligation to update any forward-looking statements whether as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise.

Overview

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

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

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil demand. In response, OPEC+ initiated discussions to lower production to support energy prices. By mid-March 2020, with OPEC+ unable to agree on cuts, crude oil prices declined to less than $25 per barrel, and subsequently fell below $20 per barrel, compared to $59.80 at December 31, 2019. These declines in prices have adversely affected the economics of our existing wells and planned future development, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020. Additional impacts to our results of operations for the three months ended March 31, 2020 were mitigated by hedges in place on 95% of our oil production, however, we will unlikely be able to replace our current hedge positions with new positions at comparable prices given current economic conditions. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The substantial decline in oil price has increased the volatility and amplitude of risks we face as described in this report and in our Annual Report on Form 10-K for the year ended December 31, 2019. If oil prices do not improve, capital availability, our liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. There is uncertainty around the timing and recovery of the global economy from COVID-19 and its effects on the supply and demand for crude oil. Therefore, we expect continued volatility and uncertainty in the outlook for near to medium term oil prices.

The COVID-19 pandemic has caused a severe decline in current and estimated future oil prices. However, as of April 20, 2020, we have hedged 4,034,000 barrels of oil, or approximately 95% of our expected remaining 2020 oil production and 3,007,500 barrels of our expected 2021 oil production, at price levels that provide some economic certainty to our cash flows. In addition, we have hedged 2,450,000 MMbtu of natural gas, or approximately 25% of our expected remaining 2020 natural gas production, and 3,650,000 MMbtu of our expected 2021 natural gas production. We focus our efforts on increasing oil, natural gas and NGL 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. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

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.
24
Three Months Ended March 31, 2020 Compared with Three Months Ended March 31, 2019

  Three Months Ended March 31, Increase (Decrease)
2020 2019 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues
Oil, gas and NGL production $ 79,566    $ 101,705    $ (22,139)   (22) %
Other operating revenues —    275    (275)   (100) %
Total operating revenues 79,566    101,980    (22,414)   (22) %
Operating Expenses
Lease operating expense 11,081    11,277    (196)   (2) %
Gathering, transportation and processing expense 4,412    1,723    2,689    156  %
Production tax expense (2,508)   3,893    (6,401)   *nm   
Exploration expense 31    25    6    24  %
Impairment and abandonment expense 1,265,426    322    1,265,104    *nm   
(Gain) loss on sale of properties —    (5)   5    (100) %
Depreciation, depletion and amortization 74,925    72,610    2,315    3  %
Unused commitment 4,458    4,469    (11)   —  %
General and administrative expense (1)
10,215    12,660    (2,445)   (19) %
Merger transaction expense —    2,414    (2,414)   (100) %
Other operating expense, net 55    (24)   79    *nm   
Total operating expenses $ 1,368,095    $ 109,364    $ 1,258,731    1,151  %
Production Data:
Oil (MBbls) 1,587    1,720    (133)   (8) %
Natural gas (MMcf) 4,356    3,756    600    16  %
NGLs (MBbls) 595    452    143    32  %
Combined volumes (MBoe) 2,908    2,798    110    4  %
Daily combined volumes (Boe/d) 31,956    31,089    867    4  %
Average Realized Prices before Hedging:
Oil (per Bbl) $ 42.69    $ 50.82    $ (8.13)   (16) %
Natural gas (per Mcf) 1.31    2.21    (0.90)   (41) %
NGLs (per Bbl) 10.32    13.29    (2.97)   (22) %
Combined (per Boe) 27.36    36.35    (8.99)   (25) %
Average Realized Prices with Hedging:
Oil (per Bbl) (2)
$ 60.87    $ 54.01    $ 6.86    13  %
Natural gas (per Mcf) 1.31    1.98    (0.67)   (34) %
NGLs (per Bbl) 10.32    13.29    (2.97)   (22) %
Combined (per Boe) (2)
37.28    38.01    (0.73)   (2) %
Average Costs (per Boe):
Lease operating expense $ 3.81    $ 4.03    $ (0.22)   (5) %
Gathering, transportation and processing expense 1.52    0.62    0.90    145  %
Production tax expense (0.86)   1.39    (2.25)   *nm   
Depreciation, depletion and amortization 25.77    25.95    (0.18)   (1) %
General and administrative expense (1)
3.51    4.52    (1.01)   (22) %

*Not meaningful.
(1)Included in general and administrative expense is long-term cash and equity incentive compensation of $0.5 million (or $0.16 per Boe) and $2.7 million (or $0.97 per Boe) for the three months ended March 31, 2020 and 2019, respectively.
(2)Included $8.3 million (or $5.26 per Bbl and $2.87 per Boe) of oil hedge income during the three months ended March 31, 2020 associated with amending certain oil hedge contracts to terminate future hedged volumes.
25
Production Revenues and Volumes. Production revenues decreased to $79.6 million for the three months ended March 31, 2020 from $101.7 million for the three months ended March 31, 2019. The decrease in production revenues was due to a 25% decrease in average realized prices before hedging, offset by a 4% increase in production volumes. The decrease in average realized prices before hedging decreased production revenues by approximately $25.1 million, while the increase in production volumes increased production revenues by approximately $3.0 million.

Lease Operating Expense ("LOE"). LOE was $11.1 million for the three months ended March 31, 2020 and $11.3 million for the three months ended March 31, 2019. LOE for the three months ended March 31, 2020 included additional costs related to annual compressor maintenance. LOE for the three months ended March 31, 2019 included additional costs related to adverse weather impacting field operations in both the Northeast Wattenberg and Hereford fields. LOE decreased to $3.81 per Boe for the three months ended March 31, 2020 from $4.03 per Boe for the three months ended March 31, 2019.

Gathering, Transportation and Processing Expense ("GTP"). GTP expense increased to $1.52 per Boe for the three months ended March 31, 2020 from $0.62 per Boe for the three months ended March 31, 2019.

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

The increase in GTP per Boe for the three months ended March 31, 2020 compared to the three months ended March 31, 2019 was due to an increase in 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 negative $2.5 million for the three months ended March 31, 2020 from $3.9 million for the three months ended March 31, 2019. Production tax expense for both periods included an annual true up of Colorado ad valorem tax based on actual assessments. 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 6.0% and 8.5% for the three months ended March 31, 2020 and 2019, respectively. The decrease in the rate for the three months ended March 31, 2020 was due to a decrease in our ad valorem tax effective tax rate.

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

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

Market conditions led to a decline in the recoverability of the carrying value of our oil and gas properties. Since the carrying amount of our oil and gas properties was no longer recoverable, we impaired the carrying value to fair value. Therefore, we recognized non-cash impairment charges for the three months ended March 31, 2020. Our impairment and abandonment expense for the three months ended March 31, 2020 and 2019 is summarized below:
26

Three Months Ended March 31,
2020 2019
Impairment of proved oil and gas properties $ 1,188,566    $ —   
Impairment of unproved oil and gas properties 76,298    —   
Abandonment expense 562    322   
Total impairment and abandonment expense $ 1,265,426    $ 322   

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

Depreciation, Depletion and Amortization ("DD&A"). DD&A increased to $74.9 million for the three months ended March 31, 2020 compared with $72.6 million for the three months ended March 31, 2019. The increase of $2.3 million was a result of a 4% increase in production and an 1% decrease in the DD&A rate for the three months ended March 31, 2020 compared with the three months ended March 31, 2019. The increase in production accounted for a $2.9 million increase in DD&A expense while the decrease in the DD&A rate accounted for a $0.6 million decrease in DD&A expense.

Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the three months ended March 31, 2020, the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.77 per Boe compared with $25.95 per Boe for the three months ended March 31, 2019. Based on the impairment expense recorded on March 31, 2020, we expect our future DD&A rate to decrease by approximately 70% for the remainder of 2020.

Unused Commitments. Unused commitments expense of $4.5 million for both the three months ended March 31, 2020 and 2019 related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense decreased to $10.2 million for the three months ended March 31, 2020 from $12.7 million for the three months ended March 31, 2019. General and administrative expense on a Boe basis decreased to $3.51 for the three months ended March 31, 2020 from $4.52 for the three months ended March 31, 2019.

Included in general and administrative expense is long-term cash and equity incentive compensation of $0.5 million and $2.7 million for the three months ended March 31, 2020 and 2019, respectively. The components of long-term cash and equity incentive compensation for the three months ended March 31, 2020 and 2019 are shown in the following table:

  Three Months Ended March 31,
  2020 2019
  (in thousands)
Nonvested common stock $ 1,150    $ 1,796   
Nonvested common stock units 280    294   
Nonvested performance cash units (1)
(974)   632   
Total $ 456    $ 2,722   

(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.

27
Merger Transaction Expense. Merger transaction expense of $2.4 million for the three months ended March 31, 2019 included severance, consulting, advisory, legal and other merger-related fees that were not capitalized as part of the Merger.

Interest Expense. Interest expense increased to $14.4 million for the three months ended March 31, 2020 from $13.7 million for the three months ended March 31, 2019. The increase for the three months ended March 31, 2020 was due to increased borrowings under the Amended Credit Facility during the three months ended March 31, 2020. See Note 4 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative gain was $192.2 million for the three months ended March 31, 2020 compared with a loss of $105.2 million for the three months ended March 31, 2019. The gain for the three months ended March 31, 2020 compared to the loss for the three months ended March 31, 2019 was related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of March 31, 2020 and 2019 or during the periods then ended.

The fair value of our open, but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility during the three months ended March 31, 2020 due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher wellhead revenues in the future.

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

  Three Months Ended March 31,
  2020 2019
  (in thousands)
Realized gain (loss) on derivatives (1)
$ 28,836    $ 4,649   
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
1,330    (19,759)  
Unrealized gain (loss) on derivatives (1)
162,022    (90,081)  
Total commodity derivative gain (loss) $ 192,188    $ (105,191)  

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

During the three months ended March 31, 2020, approximately 95% of our oil volumes were subject to financial hedges, which resulted in an increase in oil income of $20.5 million. We also amended certain oil hedge contracts to terminate future hedged volumes, which resulted in additional oil income of $8.3 million during the three months ended March 31, 2020. During the three months ended March 31, 2019, approximately 89% of our oil volumes and 34% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $5.5 million and a decrease in natural gas income of $0.9 million after settlements.

The COVID-19 pandemic caused a severe decline in current and estimated future oil and gas prices during the three months ended March 31, 2020. As the duration of the COVID-19 pandemic is uncertain, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.

Income Tax (Expense) Benefit. For the three months ended March 31, 2020 and 2019, income tax benefit of $95.3 million and $29.7 million was recognized, respectively. For the three months ended March 31, 2020, we determined that it was more likely than not that we would not be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled
28
reversal of deferred tax assets and liabilities, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of positive and negative evidence. As a result of the analysis conducted, we recorded a valuation allowance on the net deferred tax asset in excess of deferred tax liabilities. For the three months ended March 31, 2020,we have recorded a deferred tax liability of $2.1 million for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses. We continue to consider all available evidence in assessing the need for a valuation allowance on our deferred tax assets.

Capital Resources and Liquidity

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

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

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

As of March 31, 2020, our effective borrowing capacity under the Amended Credit Facility was $500.0 million, which was further reduced by $26.0 million to $379.0 million due to an outstanding irrevocable letter of credit related to a firm transportation agreement. The letter of credit will begin reducing ratably per month beginning April 1, 2020 until it expires on August 31, 2021. At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under the Amended Credit Facility. At March 31, 2020, we had cash and cash equivalents of $11.2 million and $95.0 million outstanding under the Amended Credit Facility.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from the reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt. We are in the process of our semi-annual borrowing base redetermination and expect to finalize it by mid-May. As a result of current market conditions, we expect our borrowing capacity could be reduced by an amount up to 50% and may include higher LIBOR margin pricing.

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 2020 and a portion of 2021.

Cash Flow from Operating Activities

Net cash provided by operating activities for the three months ended March 31, 2020 and 2019 was $76.8 million and $77.7 million, respectively. The slight decrease in net cash provided by operating activities was primarily due to a decrease in production revenues offset by an increase in cash settlements of derivatives.

Commodity Hedging Activities

Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict.
29
To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap and swaption contracts to receive fixed prices for a portion of our production. At March 31, 2020, we had in place crude oil swaps covering portions of our 2020 and 2021 production and crude oil swaptions covering portions of our 2022 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. The following table includes all hedges entered into through April 20, 2020.

Contract Total
Hedged
Volumes 		Quantity
Type 		Weighted
Average
Fixed
Price
Index
Price (1)
Swap Contracts:
2020
Oil 4,034,000    Bbls $ 57.48    WTI
Natural gas 2,450,000    MMBtu $ 1.70    NWPL
2021
Oil 3,007,500    Bbls $ 54.71    WTI
Natural gas 3,650,000    MMBtu $ 2.14    NWPL
Swaption Contracts:
2022
Oil 1,092,000    Bbls $ 55.08    WTI

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

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:

  Three Months Ended March 31,
Basin/Area 2020 2019
  (in millions)
DJ Basin $ 69.0    $ 123.5   
Other 1.0    2.6   
Total $ 70.0    $ 126.1   

30
  Three Months Ended March 31,
  2020 2019
  (in millions)
Acquisitions of proved and unproved properties and other real estate $ —    $ 0.3   
Drilling, development, exploration and exploitation of oil and natural gas properties 68.7    111.9   
Gathering and compression facilities 1.0    8.4   
Geologic and geophysical costs 0.2    2.9   
Furniture, fixtures and equipment 0.1    2.6   
Total $ 70.0    $ 126.1   

For the quarter ended June 30, 2020, capital expenditures are anticipated to be approximately $40.0 million to finish active drilling and completion projects. As oil prices have declined significantly due to the COVID-19 pandemic, we have deferred planned drilling and completion activity maintaining our opportunity for future development until oil prices improve to a level that allows us to meet our target return threshold. We may continue to adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control.

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 2020 and a portion of 2021 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 $95.0 million and $140.0 million outstanding under the Amended Credit Facility as of March 31, 2020 and December 31, 2019, respectively. The Amended Credit Facility provides for a maximum commitment amount of $1.5 billion, an initial elected commitment amount of $500.0 million, and an initial borrowing base of $500.0 million. The current maturity date of the Amended Credit Facility is July 16, 2022. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.

The borrowing base is determined at the discretion of the lenders and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. If the borrowing base is reduced below the then-outstanding amount under the amended Credit Facility, we will be required to repay the excess of the outstanding amount over the borrowing base over a period of four months. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt. We are in the process of our semi-annual borrowing base redetermination and expect it to finalize by mid-May. As a result of current market conditions, we expect our borrowing capacity could be reduced by an amount up to 50% and may include higher LIBOR margin pricing.

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

Our outstanding debt is summarized below:

    As of March 31, 2020 As of December 31, 2019
  Maturity Date Principal Unamortized
Discount 		Carrying
Amount 		Principal Unamortized
Discount 		Carrying
Amount
(in thousands)
Amended Credit Facility September 14, 2023 $ 95,000    $ —    $ 95,000    $ 140,000    $ —    $ 140,000   
7.0% Senior Notes October 15, 2022 350,000    (2,163)   347,837    350,000    (2,372)   347,628   
8.75% Senior Notes June 15, 2025 275,000    (3,545)   271,455    275,000    (3,717)   271,283   
Total Long-Term Debt (1)
$ 720,000    $ (5,708)   $ 714,292    $ 765,000    $ (6,089)   $ 758,911   

(1)See Note 4 for additional information.

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

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

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

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

Contractual Obligations. A summary of our contractual obligations as of March 31, 2020 is provided in the following table:

32
  Payments Due by Year
Year 1 Year 2 Year 3 Year 4 Year 5 Thereafter Total
Twelve Months Ended March 31, 2021 Twelve Months Ended March 31, 2022 Twelve Months Ended March 31, 2023 Twelve Months Ended March 31, 2024 Twelve Months Ended March 31, 2025 After March 31, 2025
  (in thousands)
Notes payable (1)
$ 274    $ 30    $ —    $ 95,000    $ —    $ —    $ 95,304   
7.0% Senior Notes (2)
24,500    24,500    374,500    —    —    —    423,500   
8.75% Senior Notes (3)
24,063    24,063    24,063    24,063    24,063    287,028    407,343   
Firm transportation agreements (4)
25,032    15,835    14,216    14,640    14,600    1,200    85,523   
Gas gathering and processing agreements (5)
2,480    1,497    —    —    —    —    3,977   
Asset retirement obligations (6)
2,351    2,027    2,006    2,143    2,154    15,077    25,758   
Operating leases (7)
2,384    2,339    2,039    2,037    2,108    7,036    17,943   
Other (8)
991    805    805    559    —    —    3,160   
Total $ 82,075    $ 71,096    $ 417,629    $ 138,442    $ 42,925    $ 310,341    $ 1,062,508   

(1)Included in notes payable is the outstanding principal amount under our Amended Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. The current maturity date of the Amended Credit Facility is July 16, 2022. While the stated maturity date in the Amended Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of "Permitted Debt" or "Permitted Refinancing Debt" (as those terms are defined in the Amended Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent "Permitted Debt", the maturity date specified in the Amended Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022. Also included in notes payable is interest on a $26.0 million letter of credit, which will begin reducing ratably per month beginning April 1, 2020 until it expires on August 31, 2021. Interest accrues at 1.75% and 0.125% per annum for participation fees and fronting fees, respectively.
(2)On March 25, 2012, we issued $400.0 million aggregate principal amount of 7.0% Senior Notes. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $12.3 million.
(3)On April 28, 2017, we issued $275.0 million aggregate principal amount of 8.75% Senior Notes. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million.
(4)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the processing facility or pipeline.
(5)Includes a gas gathering and processing contract which requires us to deliver a minimum volume of natural gas to a midstream entity for gathering and processing on a monthly basis. The contract requires us to pay a fee associated with the contracted volumes regardless of the amount delivered.
(6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See "Critical Accounting Policies and Estimates" in Part II, Item 7 of our Annual Report on Form 10-K for the year ended December 31, 2019 for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(7)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property.
(8)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.

Off-Balance Sheet Arrangements

We do not have any off-balance sheet arrangements as of March 31, 2020.

33
Trends and Uncertainties

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

Declining Commodity Prices. The severe decline in oil prices that occurred in the first quarter of 2020 due to the COVID-19 pandemic has adversely affected the economics of our existing wells and planned future wells, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020. Additional impacts to our results of operations for the three months ended March 31, 2020 were mitigated by hedges in place on 95% of our oil production. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. If oil prices remain low for an extended period of time, drilling in our DJ projects may become uneconomic, which could affect future drilling plans and growth rates. Low commodity prices impact our revenue, which we partially mitigate with our hedging program. We currently have hedged approximately 95% and 25% of our expected remaining 2020 oil and natural gas production, respectively. In addition, we have hedged approximately 40% to 60% and 25% to 35% of our expected 2021 oil and natural gas production, respectively, at price levels that provide some economic certainty to our capital investments. Continued low commodity prices make it more challenging to hedge production at higher price levels. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.

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

Under our business continuity plan, we were rapidly able to switch to remote operations in response to the COVID-19 pandemic in early March. Beginning March 16th, we successfully transitioned to full remote access and operations, in both the Denver headquarters office and at the field level. The successful transition to remote operations has been virtually seamless.

Supply Chain Issues. We have not experienced any recent challenges with respect to obtaining oil field goods and services. If anything, there is an excess of both available at the current time. As oil service and supply companies cut work force and stack rigs and frac fleets, there is the potential for challenges on this front when activity begins to ramp up, although the related timing is highly uncertain.

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

Critical Accounting Policies and Estimates

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk.

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

34
Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. oil and natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and was especially volatile during the three months ended March 31, 2020, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the three months ended March 31, 2020, our income before income taxes would have decreased by approximately $0.2 million for each $5.00 per barrel decrease in crude oil prices and decreased by approximately $0.4 million for each $0.10 decrease per MMBtu in natural gas prices and approximately $0.5 million for each $1.00 per barrel decrease in NGL prices.

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

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

April – December 2020 For the year 2021 For the year 2022
Derivative
Volumes 		Weighted Average Price Derivative Volumes Weighted Average Price Derivative Volumes Weighted Average Price
Swaps
Oil (Bbls) 4,034,000    $ 57.48    3,007,500    $ 54.71    —    $ —   
Natural Gas (MMbtu) 2,450,000    $ 1.70    3,650,000    $ 2.14    —    $ —   
Swaptions
Oil (Bbls) —    $ —    —    $ —    1,092,000    $ 55.08   

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 March 31, 2020, we had $95.0 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 three months ended March 31, 2020 was 3.4%. A 1.0% increase in each of the average LIBOR rate and federal funds rate for the three months ended March 31, 2020 would have resulted in an estimated $0.3 million increase in interest expense assuming a similar average debt level to the three months ended March 31, 2020. We also had $350.0 million principal amount of 7.0% Senior Notes and $275.0 million principal amount of 8.75% Senior Notes outstanding at March 31, 2020.
Item 4. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of March 31, 2020, we carried out an evaluation, under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, of the 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 March 31, 2020.

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

35

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.

Item 1A. Risk Factors.

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

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

In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus. As the virus spread, global economic activity began to slow and future economic activity was forecast to slow with a resulting decline in oil and gas demand. In response, the Organization of Petroleum Exporting Countries ("OPEC"), along with non-OPEC oil-producing countries (collectively known as "OPEC+"), initiated discussions to lower production to support energy prices. By mid-March 2020, with OPEC+ unable to agree on cuts, crude oil prices declined to less than $25 per barrel, and subsequently fell below $20 per barrel, compared to $59.80 at December 31, 2019. These declines in prices have adversely affected the economics of our existing wells and planned future development, which led to impairments of both proved and unproved oil and gas properties during the three months ended March 31, 2020. Additional impacts to our results of operations for the three months ended March 31, 2020 were mitigated by hedges in place on 95% of our oil production, however, we will unlikely be able to replace our current hedge positions with new positions at comparable prices given current economic conditions. The degree to which the COVID-19 pandemic will adversely impact our future operations and results will depend on future developments, which are highly uncertain and cannot be predicted, including, but not limited to, the duration of the spread of the outbreak, its severity, the actions to contain the virus and treat its impact, its impact on the economy and market conditions, and how quickly and to what extent normal economic and operating conditions can resume. The substantial decline in oil price has increased the volatility and amplitude of risks we face as described in this report and in our Annual Report on Form 10-K for the year ended December 31, 2019. If oil prices do not improve, capital availability, our liquidity and profitability will be adversely affected, particularly after our current hedges are realized in 2020 and 2021. There is uncertainty around the timing and recovery of the global economy from COVID-19 and its effects on the supply and demand for crude oil. Therefore, we expect continued volatility and uncertainty in the outlook for near to medium term oil prices.

If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time, we will be required to take an impairment against the carrying values of our properties.

Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to take an impairment against the carrying value of our properties. An impairment constitutes a non-cash charge to earnings. For the three months ended March 31, 2020, we recorded non-cash impairment charges of approximately $1.3 billion on proved and unproved oil and gas properties, and if market or other economic conditions deteriorate further or if oil and gas prices continue to decline, we may incur additional impairment charges, which may have a material adverse effect on our results of operations.
36
Any inability to comply with the covenants under our Amended Credit Facility may raise substantial doubt about our ability to continue as a going concern.

If we fail to comply with any covenants under our Amended Credit Facility, an event of default could result, in which event we will discuss available options with the lenders, which may include covenant relief or other amendments to the Amended Credit Facility. If such discussions were ultimately unsuccessful and an Event of Default exists, all outstanding amounts under the Amended Credit Facility may become due and payable and we may not have other sources of capital to repay such amounts. Such an occurrence could also lead to an event of default under the indentures governing our senior notes. Any such occurrence could raise substantial doubt about our ability to continue as a going concern. There is no assurance that any particular actions with respect to refinancing or restructuring our debt or curing potential defaults under our debt instruments could be completed or would be sufficient. Any such actions may have a material adverse effect on the value of our common stock.

If we cannot meet the financial compliance standards 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.

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

•average market capitalization of not less than $50 million over a 30 trading day period and stockholders' equity of not less than $50 million;
•average closing share price of $1.00 over a 30 trading day period; and
•average market capitalization of not less than $15 million over a 30 day trading period, which is a minimum threshold for continued listing with no cure period.

On March 10, 2020, we were notified by the NYSE that the average closing price of our common stock over the prior 30- consecutive trading day period was below that level. The NYSE Listed Company Manual sets out rules and processes to cure non-compliance with this standard. For instance, an issuer generally has six months to cure the listing standard related to stock price (including through a reverse-stock split, which was approved at the annual stockholders meeting on April 28, 2020), during which time the issuer's common stock would continue to be traded on the NYSE, subject to compliance with the other continued listing standards. However, an immediate delisting could occur if the trading price of the stock falls below a level determined by the NYSE. A delisting of our common stock from the NYSE could negatively impact us because it could reduce the liquidity and market price of our common stock and reduce the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing, and/or diminish the value of equity incentives available to provide to our employees.

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

Unregistered Sales of Securities

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

Issuer Purchases of Equity Securities

The following table contains information about our acquisitions of equity securities during the three months ended March 31, 2020:

Period
Total
Number of
Shares (1)
Weighted
Average Price
Paid Per
Share 		Total Number of 
Shares (or Units)
Purchased as
Part of Publicly
Announced Plans
or Programs 		Maximum Number
(or Approximate 
Dollar Value)
of Shares (or
Units) that May
Yet Be Purchased
Under the Plans or
Programs
January 1 – 31, 2020 —    $ —    —    —   
February 1 – 29, 2020 623,758    1.02    —    —   
March 1 – 31, 2020 860    0.25    —    —   
Total 624,618    1.02    —    —   

37
(1)Represents shares delivered by employees to satisfy tax withholding obligations resulting from the vesting of restricted shares of common stock issued pursuant to our employee incentive plans.

Item 3. Defaults upon Senior Securities.

Not applicable.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

Not applicable.

Item 6. Exhibits.

Exhibit
Number 		Description of Exhibits
22
31.1
31.2
32.1
32.2
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).

38
SIGNATURES

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

  HIGHPOINT RESOURCES CORPORATION
Date: May 4, 2020 By:   /s/ R. Scot Woodall
  R. Scot Woodall
  Chief Executive Officer and President
  (Principal Executive Officer)
Date: May 4, 2020 By:   /s/ David R. Macosko
  David R. Macosko
  Senior Vice President-Accounting
  (Principal Accounting Officer)

39
HighPoint Resources (NYSE:HPR)
Historical Stock Chart
From Mar 2024 to Apr 2024 Click Here for more HighPoint Resources Charts.
HighPoint Resources (NYSE:HPR)
Historical Stock Chart
From Apr 2023 to Apr 2024 Click Here for more HighPoint Resources Charts.