HighPoint Resources (HPR) 8-K Other Events

Exhibit 99.1

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-K*

(Mark One)

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

For the fiscal year ended December 31, 2019

or

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

For the transition period from                     to                     

Commission file number 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 office, 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, $.001 par value	HPR	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.    ☐  Yes    ☑  No

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.    ☐  Yes    ☑  No

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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.    ☐

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

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2019 was $197,315,478 (based on the closing price of $91.00 per share as of the last business day of the fiscal quarter ended June 30, 2019).

As of February 4, 2020, the registrant had 4,273,391 outstanding shares of $0.001 per share par value common stock.

* This annual report on Form 10-K for the year ended December 31, 2019 originally filed with the SEC on February 26, 2020 has been updated to reflect the 1-for-50 reverse stock split effected by HighPoint Resources Corporation on October 30, 2020. The updated information contained herein is not an amendment to, or restatement of, the the registrant’s Annual Report on Form 10-K for the year ended December 31, 2019 and does not modify or update the disclosures therein in any way, other than to reflect the reverse stock split. See Note 16 to the Consolidated Financial Statements for additional information.

DOCUMENTS INCORPORATED BY REFERENCE

The information required in Part III of this Annual Report on Form 10-K is incorporated by reference from the registrant’s definitive proxy statement for the registrant’s Annual Meeting of Stockholders to be held in May 2020 to be filed pursuant to Regulation 14A no later than 120 days after the end of the registrant’s fiscal year ended December 31, 2019.

GLOSSARY OF OIL, NATURAL GAS AND NGL TERMS

The following are abbreviations and definitions of certain terms used in this document, which are commonly used in the oil and gas industry:

Bbl. Stock tank barrel, or 42 U.S. gallons liquid volume.

Bcf. Billion cubic feet of natural gas.

Boe. Barrel of oil equivalent, determined by converting gas volumes to barrels of oil equivalent using the ratio of six Mcf of natural gas to one Bbl of crude oil, condensate or natural gas liquids.

Boe/d. Boe per day.

Btu or British thermal unit. The quantity of heat required to raise the temperature of one pound of water by one degree Fahrenheit.

Completion. Refers to installation of permanent equipment for production of oil or gas, or, in the case of a dry well, to reporting to the appropriate authority that the well has been abandoned.

Condensate. A mixture of hydrocarbons that exists in the gaseous phase at original reservoir temperature and pressure, but that, when produced, is in the liquid phase at surface pressure and temperature.

Developed acreage. The number of acres that are allocated or assignable to productive wells or wells capable of production.

Development well. A well drilled within the proved area of a natural gas or oil reservoir to the depth of a stratigraphic horizon known to be productive.

Dry hole or Dry well. An exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.

EBITDAX. Earnings before interest, taxes, depreciation, depletion, amortization and exploration expenses.

EHS. Environmental, Health and Safety.

Environmental Impact Statement. A more detailed study of the potential direct, indirect and cumulative impacts of a federal project that is subject to public review and potential litigation.

EPA. The United States Environmental Protection Agency.

E&P waste. Exploration and production waste, intrinsic to oil and gas drilling and production operations.

Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

Field. An area consisting of either a single reservoir or multiple reservoirs, all grouped on or related to the same individual geological structural feature and/or stratigraphic condition.

Gross acres or gross wells. The total acres or wells, as the case may be, in which a working interest is owned.

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Henry Hub. The Erath, LA settlement point price as quoted in Platt’s Gas Daily.

Horizontal drilling. A drill rig operation of drilling vertically to a defined depth and then mechanically steering the drill bit to drill horizontally within a designated zone typically defined as the prospective pay zone to be completed for oil and or gas.

Hydraulic fracturing. The injection of water, sand and additives under pressure, usually down casing that is cemented in the wellbore, into prospective rock formations at depth to stimulate natural gas and oil production.

Identified drilling locations. Total gross locations specifically identified and scheduled by management as an estimation of our multi-year drilling activities on existing acreage. Our actual drilling activities may change depending on the availability of capital, regulatory approvals, seasonal restrictions, natural gas and oil prices, costs, drilling results and other factors.

MBbls. Thousand barrels of crude oil or other liquid hydrocarbons.

MBoe. Thousand barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

Mcf. Thousand cubic feet of natural gas.

MMBbls. Million barrels of crude oil or other liquid hydrocarbons.

MMBoe. Million barrels of oil equivalent, determined using the ratio of one Bbl of crude oil, condensate or natural gas liquids to six Mcf of natural gas.

MMBtu. Million British thermal units.

MMcf. Million cubic feet of natural gas.

Mt. Belvieu. The Mt. Belvieu, TX settlement point price as quoted by Oil Price Information Service.

Net acres or net wells. The sum of the fractional working interest owned in gross acres or gross wells, as the case may be.

Net revenue interest. An owner’s interest in the revenues of a well after deducting proceeds allocated to royalty and overriding interests.

NGLs. Natural gas liquids.

NWPL. Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC.

Percentage of proceeds contracts. Under percentage of proceeds (POP) contracts, processors receive an agreed upon percentage of the actual proceeds of the sale of the dry natural gas and NGLs.

Play. A term used to describe an accumulation of oil and/or natural gas resources known to exist, or thought to exist based on geotechnical research, over a large area.

Plugging and abandonment. Refers to the sealing off of fluids in the strata penetrated by a well so that the fluids from one stratum will not escape into another or to the surface. Regulations of all states require plugging of abandoned wells.

Productive well. Producing wells and wells capable of production, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities.

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Prospect. A specific geographic area which, based on supporting geological, geophysical or other data and also preliminary economic analysis using reasonably anticipated prices and costs, is deemed to have potential for the discovery of commercial hydrocarbons.

Proved developed reserves. Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved reserves. The quantities of oil, natural gas and natural gas liquids, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain.

Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Proved undeveloped reserves on undrilled acreage are limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having proved undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years of initial booking, unless the specific circumstances justify a longer time. No proved undeveloped reserves can be attributed to any acreage for which an application of fluid injection or other improved recovery technique is contemplated unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

Recompletion. The process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.

Reservoir. A porous and permeable underground formation containing a natural accumulation of producible natural gas and/or oil that is confined by impermeable rock or water barriers and is separate from other reservoirs.

SEC. U.S. Securities and Exchange Commission.

Standardized Measure. The present value of estimated future cash inflows from proved oil, natural gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

Undeveloped acreage. Lease acreage on which wells have not been drilled or completed to a point that would permit the production of economic quantities of oil and natural gas regardless of whether such acreage contains proved reserves.

Working interest. The operating interest that gives the owner of such interest the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner of such interest to pay a share of the costs of drilling and production operations.

WTI. West Texas Intermediate price as quoted on the New York Mercantile Exchange.

WTI Cushing. The West Texas Intermediate price at the Cushing, OK settlement point as quoted by Bloomberg, using crude oil price bulletins.

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CAUTIONARY NOTE REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K contains “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, (the “Securities Act”), Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”), and the Private Securities Litigation Reform Act of 1995. Forward-looking statements include statements about our future strategy, plans, estimates, beliefs, timing and expected performance.

All statements in this report, other than statements of historical fact, are forward-looking statements. Forward-looking statements may be found in “Items 1 and 2. Business and Properties”, “Item 1A. Risk Factors”, “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” and other sections of this Annual Report on Form 10-K. In some cases, you can identify forward-looking statements by terminology such as “expect”, “seek”, “believe”, “upside”, “will”, “may”, “expect”, “anticipate”, “plan”, “will be dependent on”, “project”, “potential”, “intend”, “could”, “should”, “estimate”, “predict”, “pursue”, “target”, “objective”, or “continue”, the negative of such terms or other comparable terminology.

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 the forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, the following risks and uncertainties:

• volatility of market prices received for oil, natural gas and NGLs;

• actual production being less than estimated;

• changes in the estimates of proved reserves;

• availability of midstream and downstream markets to sell our products;

• reductions in the borrowing base under our revolving bank credit facility (sometimes referred to as the “Amended Credit Facility”);

• availability of capital at a reasonable cost;

• legislative or regulatory changes that can affect our ability to permit wells and conduct operations, including ballot initiatives seeking excessive setbacks, drilling moratoria or bans on hydraulic fracturing;

• availability of third party goods and services at reasonable rates;

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

• other uncertainties, including the factors discussed below and elsewhere in this Annual Report on Form 10-K, particularly in “Item 1A. Risk Factors”, all of which are difficult to predict.

In light of these and other risks, uncertainties and assumptions, anticipated events addressed in forward looking statements may not occur.

The forward-looking statements contained in this Annual Report on Form 10-K are largely based on our expectations, which reflect estimates and assumptions made by our management. Although we believe such estimates and assumptions to be reasonable, they are inherently uncertain and involve a number of risks and uncertainties that are beyond our control. In addition, management’s assumptions about future events may prove to be inaccurate. Management cautions all readers that the forward-looking statements contained in this Annual Report on Form 10-K are not guarantees of future performance, and we cannot assure any reader that our expectations will be realized or that future forward-looking events and circumstances will occur as anticipated. Actual results may differ materially from those anticipated or implied in the forward-looking statements due to many factors including those listed above and in “Item 1A. Risk Factors” and elsewhere in this Annual Report on Form 10-K. All forward-looking statements speak only as of the date of this Annual Report on Form 10-K. Readers should not place undue reliance on these forward-looking statements, which reflect management’s views only as of the date hereof. Other than as required under the securities laws, we do not intend, and do not undertake any obligation to, update or revise any forward-looking statements as a result of changes in internal estimates or expectations, new information, subsequent events or circumstances or otherwise. These cautionary statements qualify all forward-looking statements attributable to us or persons acting on our behalf.

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PART I

Items 1 and 2. Business and Properties.

BUSINESS

General

HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”, “we”, “our” or “us”) is an independent oil and gas company engaged in the exploration, development and production of oil, natural gas and natural gas liquids (“NGLs”). We 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. We currently conduct our 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.

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.

We maintain a website at the address http://www.hpres.com. No information on our website is incorporated by reference herein or deemed to be part of this Annual Report on Form 10-K. We make available free of charge through our website our annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K and all amendments to those reports as soon as reasonably practicable after such material is electronically filed with or furnished to the SEC via EDGAR and posted at http://www.sec.gov. Additionally, our Code of Business Conduct and Ethics, which includes our code of ethics for senior financial management, Corporate Governance Guidelines, Corporate Responsibility Report, and the charters of our Audit Committee, Compensation Committee, Reserves and EHS Committee and Nominating and Corporate Governance Committee are posted on our website and are available in print free of charge to any stockholder who requests them. Requests should be sent by mail to our corporate secretary at our principal office at 555 17^th Street, Suite 3700, Denver, Colorado 80202. We intend to disclose on our website any amendments or waivers to our Code of Business Conduct and Ethics that are required to be disclosed pursuant to Item 5.05 of Form 8-K. Our website contains information provided by other sources that we believe are reliable. We cannot assure you that the information obtained from other sources is accurate or complete.

We operate in one industry segment, which is the exploration, development and production of oil and natural gas, and all operations are conducted in the United States. Consequently, we currently report a single reportable segment. See “Financial Statements” and the notes to our consolidated financial statements for financial information about this reportable segment.

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PROPERTIES

Overview

As of December 31, 2019, we have one key area of production: the DJ Basin.

Our acreage positions in the DJ Basin are predominantly located in Colorado’s eastern plains and parts of southeastern Wyoming.

DJ Basin Key Statistics

• Estimated proved reserves as of December 31, 2019 - 127.4 MMBoe.

• Producing wells - We had interests in 568 gross (377.9 net) producing wells as of December 31, 2019, and we serve as operator of 423 gross wells.

• 2019 net production - 12,538 MBoe.

• Acreage - We held 66,043 net undeveloped and 76,544 net developed acres as of December 31, 2019.

• Capital expenditures - Our capital expenditures for 2019 were $355.0 million for participation in the drilling of 74 gross (62.3 net) wells, acquisition of leasehold acres and construction of gathering facilities.

• As of December 31, 2019, we were drilling 1 gross (1 net) well, and we were waiting to complete 34 gross (22.9 net) wells.

• Based on our proved reserves as of January 1, 2020, we have a 64% weighted average working interest in our producing wells in the DJ Basin.

The DJ Basin is a high growth oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. We believe that the DJ Basin offers us significant growth opportunities with potential acreage additions to our current leasehold position, possible development of additional formations, increased utilization of extended reach (long lateral) horizontal wells, well completion optimization and ongoing cost reduction.

The DJ Basin is our core area of operation; we drilled 72 gross (62.1 net) operated wells and placed 69 gross (63.1 net) operated wells on initial flowback there in 2019. We had four rigs operating at the beginning of 2019 and decreased the rig count to two during the year. In 2019, we continued to drill extended reach horizontal wells in the Niobrara and Codell formations across the greater Northeast Wattenberg area of the DJ Basin, continuing to optimize our completion technology and establishing a scalable development program. In addition, we focused on the initial development of the Hereford field assets acquired in the Merger. The combination of this development along with nearby competitor activity continued to de-risk our acreage in the two areas.

Our oil production from the DJ Basin is sold at the lease and is either trucked or transported by pipelines to various markets. Our gas production from the DJ Basin is gathered and processed by third parties, and we receive residue gas and NGL revenue under percentage of proceeds or fee-based contracts.

Oil and Gas Data

Proved Reserves

The following table presents our estimated net proved oil, natural gas and NGL reserves at each of December 31, 2019, 2018 and 2017 based on reserve reports prepared by us and audited by independent third party petroleum engineers. While we are not required by the SEC or accounting regulations or pronouncements to have our reserve estimates independently audited, such an audit is required under our Amended Credit Facility. All of our proved reserves included in our reserve reports are located in North America. Netherland, Sewell & Associates, Inc. (“NSAI”) audited all of our reserves estimates at December 31, 2019, 2018 and 2017. NSAI is retained by and reports to the Reserves and EHS Committee of our Board of Directors. When compared on a well-by-well or lease-by-lease basis, some of our internal estimates of net proved reserves are greater and some are less than NSAI’s estimates. However, in the aggregate, NSAI’s estimates of total net proved reserves are

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within 10% of our internal estimates. In addition to a third party audit, our reserves are reviewed by our Reserves and EHS Committee. The Reserves and EHS Committee reviews the final reserves estimates in conjunction with NSAI’s audit letter and meets with the key representative of NSAI to discuss NSAI’s review process and findings.

	As of December 31,
Proved Reserves: (1)	2019		2018		2017
Proved Developed Reserves:
Oil (MMBbls)		25.7		24.5		17.4
Natural gas (Bcf)		89.4		84.0		74.5
NGLs (MMBbls)		11.2		12.9		11.7
Total proved developed reserves (MMBoe)		51.8		51.4		41.5
Proved Undeveloped Reserves:
Oil (MMBbls)		48.4		34.5		22.2
Natural gas (Bcf)		91.9		56.3		68.4
NGLs (MMBbls)		11.9		9.3		10.7
Total proved undeveloped reserves (MMBoe) (2)		75.6		53.2		44.3
Total Proved Reserves (MMBoe) (3)		127.4		104.6		85.8

(1) Our proved reserves were determined in accordance with SEC guidelines, using the average of the prices on the first day of each month in 2019 for natural gas (Henry Hub price) and oil (WTI Cushing price), subject to certain adjustments, or $2.58 per MMBtu of natural gas and $55.85 per barrel of oil, respectively, without giving effect to hedging transactions. The average NGL price per barrel was based on a percentage of the average oil price, subject to certain adjustments. We currently do not include future reclamation costs net of salvage value in the calculation of our proved reserves.

(2) Approximately 59%, 51% and 52% of our estimated proved reserves (by volume) were undeveloped for the years ended December 31, 2019, 2018 and 2017, respectively.

(3) Total proved reserves have been reduced for the sale of non-core oil and gas properties in the amount of 11.2 MMBoe for the year ended December 31, 2017.

The data in the above table represent estimates only. Oil, natural gas and NGLs reserves are estimates of accumulations of oil, natural gas and NGLs that cannot be measured exactly. The accuracy of any reserves estimate is a function of the quality of available data and engineering and geological interpretation and judgment. Accordingly, reserves estimates may vary from the quantities of oil, natural gas and NGLs that are ultimately recovered. See “Item 1A. Risk Factors”.

The following tables illustrate the history of our proved undeveloped reserves from December 31, 2017 through December 31, 2019:

	As of December 31,
Proved Undeveloped Reserves:	2019			2018			2017
	(MMBoe)
Beginning balance		53.2			44.3			18.5
Additions from drilling program (1)(2)		32.2			41.3			31.7
Acquisitions		1.9			5.2			—
Engineering revisions (3)		0.8			(6.7	)		10.8
Price revisions		(0.4	)		0.2			0.2
Converted to proved developed		(12.1	)		(21.1	)		(13.0	)
Sold/ expired/ other (4)		—			(10.0	)		(3.9	)
Total proved undeveloped reserves (5)		75.6			53.2			44.3

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(1) The increase in proved undeveloped reserves for the year ended December 31, 2019 was related to the expansion of our drilling program in the Hereford field and a successful extension test in our Northeast Wattenberg field.

(2) The increase in proved undeveloped reserves for the year ended December 31, 2018 was primarily related to the addition of the Hereford field as a result of the Merger with Fifth Creek. The upward revisions include 41.0 MMboe related to the Hereford field that were added to the proved undeveloped reserve category as these locations are included in our near-term development plans.

(3) Negative engineering revisions for the year ended December 31, 2018 of 6.7 MMBOE are composed of 2.9 MMBoe at Hereford due to results from nine drilled but not completed (“DUC”) wells acquired in the Merger which were testing tighter well spacing, and two of which experienced mechanical issues, and 3.8 MMBoe at Northeast Wattenberg due to well under performance in a new development.

(4) For the year ended December 31, 2018, 10.0 MMboe of proved undeveloped reserves in our Northeast Wattenberg field were removed due to the Merger as a result of focusing our drilling plans to target the higher return locations in the Hereford field.

(5) Our proved undeveloped locations as of December 31, 2019 represent approximately 7 rig-years of drilling inventory which we currently plan to develop over the next 2 to 3 years. This proved undeveloped inventory represents a conservative investment decision to drill these locations within the five-year development window allowed at the time the applicable proved undeveloped reserve is booked and is only a small portion of our large resource base, much of which meets the engineering definition for proved undeveloped reserves. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with more attractive rates of return, leading us to deviate from our original development plan.

	Year Ended December 31,
	2019			2018			2017
Proved undeveloped locations converted to proved developed wells during year		64			69			51
Proved undeveloped drilling and completion capital invested (in millions)	$	262.4		$	269.1		$	136.8
Proved undeveloped facilities capital invested (in millions)	$	13.5		$	28.5		$	11.9
Percentage of proved undeveloped reserves converted to proved developed		23	%		48	%		70	%
Prior year’s proved undeveloped reserves remaining undeveloped at current year end (MMBoe)		42.4			11.2			1.6

At December 31, 2019, our proved undeveloped reserves were 75.6 MMBoe. At December 31, 2018, our proved undeveloped reserves were 53.2 MMBoe. During 2019, 12.1 MMBoe, or 23% of our December 31, 2018 proved undeveloped reserves (64 wells), were converted into proved developed reserves and required $262.4 million of drilling and completion capital and $13.5 million of facilities capital. These wells produced 2.8 MMBoe in 2019. During 2019, we added 32.2 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased proved undeveloped reserves by 0.8 MMBoe. Negative pricing revisions decreased proved undeveloped reserves by 0.4 MMBoe. The proved undeveloped reserves from December 31, 2018 that remained in the proved undeveloped reserves category at December 31, 2019 were 42.4 MMBoe.

At December 31, 2018, our proved undeveloped reserves were 53.2 MMBoe. At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. During 2018, 21.1 MMBoe, or 48% of our December 31, 2017 proved undeveloped reserves (69 wells), were converted into proved developed reserves and required $269.1 million of drilling and completion

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capital and $28.5 million of facilities capital. These wells produced 2.9 MMBoe in 2018. During 2018, we added 41.3 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Negative engineering revisions decreased proved undeveloped reserves by 6.7 MMBoe as discussed above. During 2018, 10.0 MMBoe were removed from the proved undeveloped reserves category as a result of being excluded from our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2017 that remained in the proved undeveloped reserves category at December 31, 2018 were 11.2 MMBoe.

At December 31, 2017, our proved undeveloped reserves were 44.3 MMBoe. At December 31, 2016, our proved undeveloped reserves were 18.5 MMBoe. During 2017, 13.0 MMBoe, or 70% of our December 31, 2016 proved undeveloped reserves (51 wells), were converted into proved developed reserves and required $136.8 million of drilling and completion capital and $11.9 million of facilities capital. These wells produced 2.2 MMBoe in 2017. During 2017, we added 31.7 MMBoe of proved undeveloped reserves due to drilling programs in our core development area. Positive engineering revisions increased proved undeveloped reserves by 10.8 MMBoe. During 2017, 3.9 MMBoe were removed from the proved undeveloped reserves category because they were not included in our near term development plans within the five year development window allowed at the time the applicable proved undeveloped reserves were booked. Positive pricing revisions increased proved undeveloped reserves by 0.2 MMBoe. The proved undeveloped reserves from December 31, 2016 that remained in the proved undeveloped reserves category at December 31, 2017 were 1.6 MMBoe.

We use our internal reserves estimates rather than the estimates of an independent third party engineering firm because we believe that our reservoir and operations engineers are more knowledgeable about the wells due to our continual analysis throughout the year as compared to the relatively short term analysis performed by third party engineers. We use our internal reserves estimates on all properties regardless of the positive or negative variance relative to the estimates of third party engineers. If a variance greater than 10% occurs at the field level, it may suggest that a difference in methodology or evaluation techniques exists between us and the third party engineers. We investigate any such differences and discuss the differences with the third party engineers to confirm that we used the proper methodologies and techniques in estimating reserves for the relevant field. These variances also are reviewed with our Reserves and EHS Committee. These differences are not resolved to a specified tolerance at the field or property level. In the aggregate, the third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates.

The internal review process of our wells and the related reserves estimates, and the related internal controls we utilize, include but are not limited to the following:

• A comparison is made and documented of actual and historical data from our production system to the data in the reserve database. This is intended to ensure the accuracy of the production data, which supplies the basis for forecasting.

• A comparison is made and documented of land and lease records to interest data in the reserve database. This is intended to ensure that the costs and revenues will be properly determined in the reserves estimation.

• A comparison is made of the historical costs (capital and expenses) to the capital and lease operating costs in the reserve database. Documentation lists reasons for deviation from direct use of historical data. This is intended to ensure that all costs are properly included in the reserve database.

• A comparison is made of input data to data in the reserve database of all property acquisitions, disposals, retirements or transfers to verify that all are accounted for accurately.

• Natural gas and oil prices based on the SEC pricing requirements are supplied by the third party independent engineering firm. Natural gas pricing for the first flow day of every month is collected from Henry Hub Gas Daily price and oil pricing is collected from Thomson Reuters WTI spot price. The average NGL price is based on a percentage of the WTI oil price per barrel.

• A final check is made of all economic data inputs in the reserve database by comparing them to documentation provided by our internal marketing, land, accounting, production and operations groups. This provides a second check designed to ensure accuracy of input data in the reserve database.

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• Accurate classification of reserves is verified by comparing independent classification analyses by our internal reservoir engineers and the third party engineers. Discrepancies are discussed and differences are jointly resolved.

• Internal reserves estimates are reviewed by well and by area by the Chief Operating Officer. A variance by well to the previous year-end reserve report is used in this process. This review is independent of the reserves estimation process.

• Reserves variances are discussed among the internal reservoir engineers and the Chief Operating Officer. Our internal reserves estimates are reviewed by senior management and the Reserves and EHS Committee prior to publication.

Within our Company, the technical person primarily responsible for overseeing the preparation of the reserves estimates is Paul Geiger. Mr. Geiger is our Chief Operating Officer and became responsible for our reserves estimates starting in January 2019. Mr. Geiger earned a Bachelor of Science degree in Petroleum Engineering and an MBA from the University of Texas. Mr. Geiger has over 20 years of experience in reserves and economic evaluations, as well as broad experience in production, completions, reservoir analysis and planning and development.

The reserves estimates shown herein have been independently audited by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for auditing the estimates set forth in the NSAI audit letter incorporated herein are Mr. Benjamin W. Johnson and Mr. John G. Hattner. Mr. Johnson, a Licensed Professional Engineer in the State of Texas (No. 124738), has been practicing consulting petroleum engineering at NSAI since 2007 and has over 2 years of prior industry experience. He graduated from Texas Tech University in 2005 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Hattner, a Licensed Professional Geoscientist in the State of Texas, Geophysics (No. 559), has been practicing consulting petroleum geoscience at NSAI since 1991, and has over 11 years of prior industry experience. He graduated from University of Miami, Florida, in 1976 with a Bachelor of Science Degree in Geology; from Florida State University in 1980 with a Master of Science Degree in Geological Oceanography; and from Saint Mary’s College of California in 1989 with a Master of Business Administration Degree. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserves definitions and guidelines.

NSAI performed a well-by-well audit of all of our properties and of our estimates of proved reserves and then provided us with its audit report concerning our estimates. The audit completed by NSAI, at our request, is a collective application of a series of procedures performed by NSAI. These audit procedures may be the same as or different from audit procedures performed by other independent third party engineering firms for other oil and gas companies. NSAI’s audit report does not state the degree of its concurrence with the accuracy of our estimate of the proved reserves attributable to our interest in any specific basin, property or well.

The NSAI audit process is intended to determine the percentage difference, in the aggregate, of our internal net proved reserves estimate and future net revenue (discounted at 10%) and the reserves estimate and net revenue as determined by NSAI. The audit process includes the following:

• The NSAI engineer performs an independent decline curve analysis on proved producing wells based on production and pressure data.

• The NSAI engineer may verify the production data with public data.

• The NSAI engineer uses his or her individual interpretation of the information and knowledge of the reservoir and area to make an independent analysis of proved producing reserves.

• The NSAI technical staff may prepare independent maps and volumetric analyses on our properties and offsetting properties. They review our geologic maps, log data, core data, pertinent pressure data, test information and pertinent technical analyses, as well as data from offsetting producers.

• For the reserves estimates of proved non-producing and proved undeveloped locations, the NSAI engineer will estimate the potential for depletion by analogy to other wells in the basin drilled on varying well spacing.

• The NSAI engineer will estimate the hydrocarbon recovery of the remaining gas-in-place based upon his/her knowledge and experience.

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• The NSAI engineer does not verify our working and net revenue interests or product price deductions.

• The NSAI engineer does not verify our capital costs although he/she may ask for confirming information and compare to basin analogs.

• The NSAI engineer reviews 12 months of operating cost, revenue and pricing information that we provide.

• The NSAI engineer confirms the oil and gas prices used for the SEC reserves estimate.

• NSAI confirms that its reserves estimate is within a 10% variance of our internal net reserves estimate and estimated future net revenue (discounted at 10%), in the aggregate, before an audit letter is issued.

• The audit by NSAI is not performed such that differences in reserves or revenue on a well level are resolved to any specific tolerance.

The reserves audit letter provided by NSAI states that “in our opinion the estimates shown herein of HighPoint’s reserves and future revenue are reasonable when aggregated at the proved level and have been prepared in accordance with the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers (SPE Standards). Additionally, these estimates are within the recommended 10 percent tolerance threshold set forth in the SPE Standards.” The audit letter also includes a statement of dates pertaining to the NSAI work performed, the methodology used, the assumptions made and a discussion of uncertainties that they believe are inherent in reserves estimates.

Future prices received for production and costs may vary, perhaps significantly, from the prices and costs assumed for purposes of these estimates. The Standardized Measure shown in the Financial Statements should not be construed as the current market value of the reserves. The 10% discount factor used to calculate present value, which is required by Financial Accounting Standards Board pronouncements (“FASB”), is not necessarily the most appropriate discount rate. The present value, no matter what discount rate is used, is materially affected by assumptions as to timing of future production, which may prove to be inaccurate.

From time to time, we engage NSAI to review and/or evaluate the reserves of properties that we are considering purchasing and to provide technical consulting on well testing. NSAI and its employees have no interest in those properties, and the compensation for these engagements is not contingent on NSAI’s estimates of reserves and future cash inflows for the subject properties. During 2019 and 2018, we paid NSAI approximately $245,000 and $233,000, respectively, for auditing our reserves estimates.

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Production and Cost History

The following table sets forth information regarding net production of oil, natural gas and NGLs and certain cost information for each of the periods indicated:

	Year Ended December 31,
	2019		2018		2017
Company Production Data:
Oil (MBbls)		7,668		6,330		4,203
Natural gas (MMcf)		16,614		12,864		8,952
NGLs (MBbls)		2,101		1,697		1,307
Combined volumes (MBoe)		12,538		10,171		7,002
Daily combined volumes (Boe/d)		34,351		27,866		19,184
DJ Basin – Production Data (1):
Oil (MBbls)		7,668		6,330		3,509
Natural gas (MMcf)		16,614		12,864		8,592
NGLs (MBbls)		2,101		1,697		1,294
Combined volumes (MBoe)		12,538		10,171		6,235
Daily combined volumes (Boe/d)		34,351		27,866		17,082
Uinta Oil Program – Production Data (1)(2):
Oil (MBbls)		—		—		689
Natural gas (MMcf)		—		—		348
NGLs (MBbls)		—		—		12
Combined volumes (MBoe)		—		—		759
Daily combined volumes (Boe/d)		—		—		2,079
Average Realized Prices before Hedging:
Oil (per Bbl)	$	52.86	$	62.04	$	48.37
Natural gas (per Mcf)		1.56		1.75		2.43
NGLs (per Bbl)		10.00		22.18		20.01
Combined (per Boe)		36.07		44.53		35.88
Average Realized Prices with Hedging:
Oil (per Bbl)	$	54.39	$	54.51	$	52.72
Natural gas (per Mcf)		1.50		1.76		2.52
NGLs (per Bbl)		10.00		22.18		20.01
Combined (per Boe)		36.92		39.85		38.60
Average Costs ($ per Boe):
Lease operating expense	$	3.01	$	2.74	$	3.46
Gathering, transportation and processing expense		0.85		0.46		0.37
Total production costs excluding production taxes	$	3.86	$	3.20	$	3.83
Production tax expense		1.88		3.61		2.07
Depreciation, depletion and amortization		25.62		22.46		22.85
General and administrative (3)		3.57		4.44		6.07

(1) The DJ Basin was the only development area that contained 15% or more of our total proved reserves as of December 31, 2019, 2018 and 2017.

(2) On December 29, 2017, we completed the sale of our remaining non-core assets in the Uinta Basin. As a result, the production and cost data related to the Uinta Basin as reported above includes values through the closing date of December 29, 2017. See Note 4 to the Consolidated Financial Statements for more information related to this divestiture.

(3) Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million (or $0.69 per Boe), $7.2 million (or $0.71 per Boe) and $8.3 million (or $1.18 per Boe) for the years ended December 31, 2019, 2018 and 2017, respectively.

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Productive Wells

The following table sets forth information at December 31, 2019 relating to the productive wells in which we owned a working interest as of that date.

	Oil				Gas
Basin/Area	Gross Wells		Net Wells		Gross Wells		Net Wells
DJ		558.0		371.4		10.0		6.5
Other		1.0		0.1		4.0		1.1
Total		559.0		371.5		14.0		7.6

Developed and Undeveloped Acreage

The following table sets forth information as of December 31, 2019 relating to our leasehold acreage.

	Developed Acreage				Undeveloped Acreage
Basin/Area	Gross		Net		Gross		Net
DJ		95,790		76,544		97,860		66,043
Other (1)		4,923		2,093		114,564		54,819
Total		100,713		78,637		212,424		120,862

(1) Other includes 46,583, 4,184 and 2,353 net undeveloped acres in the Paradox, Piceance and Deseret Basins, respectively.

Substantially all of the leases comprising the undeveloped acreage set forth in the table above will expire at the end of their respective primary terms unless production from the leasehold acreage has been established prior to such date, in which event the lease will remain in effect until the cessation of production. The following table sets forth, as of December 31, 2019, the expiration periods of the net undeveloped acres by area that are subject to leases summarized in the above table of undeveloped acreage.

	Net Undeveloped Acres Expiring
Basin/Area	2020		2021		2022		2023		Thereafter		Total
DJ		7,932		15,020		7,348		5,611		30,132		66,043
Other		2,012		—		—		288		52,519		54,819
Total		9,944		15,020		7,348		5,899		82,651		120,862

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Drilling Results

The following table sets forth information with respect to wells completed during the periods indicated. The information should not be considered indicative of future performance, nor should it be assumed that there is necessarily any correlation between the number of productive wells drilled and quantities or value of reserves found.

	Year Ended December 31,
	2019				2018				2017
	Gross		Net		Gross		Net		Gross		Net		��
Development
Productive		106.0		67.2		95.0		76.1		59.0		44.8
Dry		—		—		—		—		—		—
Exploratory
Productive		—		—		—		—		—		—
Dry		—		—		—		—		—		—
Total
Productive		106.0		67.2		95.0		76.1		59.0		44.8
Dry		—		—		—		—		—		—

Operations

General

In general, we serve as operator of wells in which we have a greater than 50% working interest. In addition, we seek to be the operator of wells in which we have lesser interests. As operator, we obtain regulatory authorizations, design and manage the development of a well and supervise operation and maintenance activities on a day-to-day basis. We do not own drilling rigs or the majority of the other oil field service equipment used for drilling or maintaining wells on the properties we operate. Independent contractors engaged by us provide the majority of the equipment and personnel associated with these activities. In certain circumstances we construct, operate and maintain gas gathering and water facilities associated with our operations. We employ drilling, completion, facility, production and reservoir engineers and geologists and other specialists who work to improve production rates, increase reserves and lower the cost of operating our oil and natural gas properties. We strive to minimize our impact on the communities in which we operate.

Marketing and Customers

We market all of the oil production from our operated properties. Our oil production is sold to a variety of purchasers under contracts with daily, monthly, seasonal, annual or multi-year terms, all at market prices. Purchasers include pipelines, processors, refineries, marketing companies and end users. Our oil contracts are priced off of New York Mercantile Exchange (“NYMEX”) with quality, location or transportation differentials.

Our natural gas and related NGLs are generally marketed by third parties under percentage of proceeds (“POP”) or fee-based contracts. Based on where we operate and the availability of other purchasers and markets, we believe that our production could be sold in the market in the event that it is not sold to our existing customers. However, in some circumstances, a change in customers may entail significant transition costs.

We normally sell production to a relatively small number of customers, as is customary in the development and production business. During 2019, three customers individually accounted for over 10% of our oil, gas and NGL production revenues. During 2018, four customers individually accounted for over 10% of our oil, gas and NGL production revenues. During 2017, three customers individually accounted for over 10% of our oil, gas and NGL production revenues.

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The following table sets forth information about a material long-term firm oil pipeline transportation contract, which entails a demand charge for reservation of capacity. This contract was initiated to mitigate rising transportation costs in our Hereford field in the DJ Basin. This firm transportation contract requires the pipeline to provide transportation capacity and requires us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized and expire April 30, 2025. The costs of this transportation contract are included in oil, gas and NGL production in the Consolidated Statements of Operations.

Type of Arrangement	Pipeline System / Location	Deliverable Market	Range of Gross Deliveries (Bbl/d)	Term
Firm Transport	Tallgrass Pony Express	Cushing	6,250-12,500	05/20 – 04/25

The following table sets forth information about material long-term firm natural gas pipeline transportation contracts, which entail a demand charge for reservation of capacity. These contracts were initiated to provide a guaranteed outlet for company-marketed production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. 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 and expire July 31, 2021. These transportation costs are included in unused commitments expense in the Consolidated Statements of Operations.

Type of Arrangement	Pipeline System / Location	Deliverable Market	Gross Deliveries (MMBtu/d)	Term
Firm Transport	Questar Overthrust	Rocky Mountains	50,000	08/11 – 07/21
Firm Transport	Ruby Pipeline	West Coast	50,000	08/11 – 07/21

Hedging Activities

Our hedging program is intended to mitigate the risks of volatile prices of oil, natural gas, and NGLs. Our strategic objective is to hedge 50% to 70% of our anticipated production on a forward 12-month to 18-month basis. As of February 4, 2020, we have hedged 5,857,500 barrels of oil for our 2020 production and 1,912,500 barrels of oil for our 2021 production at price levels that provide some economic certainty to our cash flows. Currently, nine of our 11 lenders (or affiliates of lenders) under our credit facility are also hedging counterparties. We are not required to post collateral for these hedges other than the security for our credit facility. For additional information on our hedging activities, see “Item 7A. Quantitative and Qualitative Disclosures About Market Risk”.

Competition

The oil and gas industry is intensely competitive, and we compete with a large number of other companies, some of which have greater resources. See the risk discussed below in “Item 1A. Risk Factors” under the caption “Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed”.

Title to Properties

As is customary in the oil and gas industry, we initially conduct only a cursory review of the title to our properties on which we do not have proved developed reserves. Prior to the commencement of drilling operations on those properties, we typically conduct a title examination and perform curative work for significant defects. To the extent title opinions or other investigations reflect title defects on those properties, we are typically responsible for curing such defects at our expense. We generally will not commence drilling operations on a property until we have cured any material title defects on such property. We have obtained title opinions on substantially all of our producing properties and believe that we utilize methods consistent with practices customary in the oil and gas industry and that our practices are adequately designed to enable us to acquire satisfactory title to our producing properties. Prior to completing an acquisition of producing oil and gas leases, we perform title reviews on the most significant leases and, depending on the materiality of the properties, we may obtain a title opinion or

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review previously obtained title opinions. However, our title review processes may not be successful in preventing disputes and losses related to actual or asserted title defects. Our oil, natural gas and NGL producing properties are subject to customary royalty and other interests, liens for current taxes, liens under our Amended Credit Facility and other burdens that we believe do not materially interfere with the use of our properties.

Environmental Matters and Regulation

General. Our operations are subject to comprehensive federal, state and local laws and regulations governing the discharge of materials into the environment, management of E&P waste, or otherwise relating to environmental protection and minimization of aesthetic impacts. Our operations are generally subject to the same environmental laws and regulations as other companies in the oil and gas exploration and production industry in the areas where we operate. These laws and regulations:

• require the acquisition of various permits before drilling commences;

• require the installation of effective emission control equipment;

• restrict the types, quantities and concentration of various substances that can be released into the environment in connection with drilling and production activities;

• limit or prohibit drilling activities on lands lying within environmentally sensitive areas, wilderness, wetlands and other protected areas, including areas proximate to residential areas and certain high-occupancy buildings;

• require measures to prevent pollution from current operations, such as E&P waste management, transportation and disposal requirements;

• require measures to prevent pollution from former operations, such as pit closure and plugging of abandoned wells;

• impose substantial penalties for any non-compliance with federal, state and local laws and regulations;

• impose substantial liabilities for any pollution resulting from our operations;

• with respect to operations affecting federal lands or leases, require time consuming environmental analysis with uncertain outcomes;

• expose us to litigation by environmental and other special interest groups; and

• impose certain compliance and regulatory reporting requirements.

These laws, rules and regulations may also restrict the rate of oil, natural gas and NGLs production below the rate that would otherwise be possible, for example, by limiting the flaring of associated natural gas from an oil well while awaiting a pipeline connection. The regulatory burden on the oil and gas industry increases the cost and delays the timing of doing business and consequently affects profitability. Additionally, Congress, state legislatures, and federal and state agencies frequently revise environmental laws and regulations, and any changes that result in delay or more stringent and costly permitting, waste handling, disposal and clean-up requirements for the oil and gas industry could have a significant impact on our operating costs.

We have made and will continue to make expenditures in our efforts to comply with all environmental regulations and requirements. We consider these a normal, recurring cost of our ongoing operations and not extraordinary. We believe that our compliance with existing requirements has been accounted for and will not have a material adverse impact on our financial condition and results of operations. However, we cannot predict the passage of or quantify the potential impact of more stringent future laws and regulations, including organized, well-funded “keep it in the ground” efforts to turn public opinion against the use of fossil fuels. For example, statewide ballot initiatives intended to impose further restrictions on oil and gas development have been pursued several times in recent years in Colorado. In particular, Proposition 112, which was included on the ballot for the November 2018 election in Colorado but was defeated at the polls, would have amended the Colorado Oil and Gas Conservation Act to, among other things, require all new oil and gas development not on federal land to be located at least 2,500 feet away from any occupied structure or broadly defined “vulnerable area”. If enacted, Proposition 112 would have effectively prohibited drilling activities across a substantial majority of the surface area of the State of Colorado, although we developed a plan to reconfigure drilling units and relocate most of our remote, rural well locations. Such reconfiguration and relocation would, however, have entailed substantial expense and delay, as well as reduced certain cost efficiencies built into our current plans. Similar proposals may be approved for the 2020 and subsequent elections. Because substantially all of our operations and reserves are located in Colorado, the passage and implementation of any such proposal could have a materially adverse effect on our operations, reserves, financial condition and business generally.

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Similarly, although Proposition 112 failed at the ballot box, 44% of the electorate, representing over one million voters, cast ballots in favor. At the same time, a new Democratic Governor was elected, along with Democratic majorities in both chambers of the General Assembly. Following the November 2018 election, Colorado enacted Senate Bill 19-181 (“SB 19-181”), which, among other things, authorizes local governments to approve the siting of and regulate the surface impacts from oil and natural gas facilities, and empowers them to adopt requirements and impose conditions that are more stringent than state regulations. The statute changes the mission of the Colorado Oil and Gas Conservation Commission (the “COGCC”) from fostering responsible and balanced development to regulating development to protect public health and the environment as the primary goal. It requires the COGCC to undertake rulemaking on environmental protection, facility siting, cumulative impacts, flowline safety, orphan wells, financial assurance, wellbore integrity, and application fees. It also requires the Air Quality Control Commission to review its leak detection and repair regulations and adopt rules to further minimize emissions of hydrocarbons and nitrogen oxides. These rulemakings, some of which were completed in late 2019 and others that will be completed in 2020 and beyond, will impose new approval and operating requirements and may have an adverse effect on our development program, particularly in terms of costs and delays in the permitting process. However, we believe that the location of our assets in rural areas of Weld County, a jurisdiction generally supportive of oil and gas development, is likely to mitigate these impacts to a significant extent.

Other environmental laws and regulations that could have a material impact on the oil and natural gas exploration and production industry and our business include the following:

National Environmental Policy Act. Oil, natural gas and NGLs exploration and production activities on federal lands and the development of federal mineral rights are subject to the National Environmental Policy Act, or NEPA. NEPA requires federal agencies, including the Departments of the Interior and Agriculture, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will have an environmental assessment prepared that assesses the potential direct, indirect and cumulative impacts of a proposed project and project alternatives. If impacts are considered significant, the agency will prepare a more detailed Environmental Impact Statement. These environmental analyses are made available for public review and comment. On January 10, 2020, the Council on Environmental Quality (“CEQ”) published a notice of proposed rulemaking that seeks comment on potential amendments that would “modernize and clarify” the current NEPA regulations and streamline environmental reviews. Potential amendments to the NEPA regulations could include setting time limits for completion of environmental reviews and no longer requiring federal agencies to consider the cumulative impacts of a project. The public comment period on the notice for proposed rulemaking ends on March 10, 2020. The proposed revisions to the NEPA regulations have not yet been finalized and will likely be subject to legal challenges. All of our current exploration and production activities, as well as proposed exploration and development plans, on federal lands and/or involving federal mineral rights require governmental permits that trigger the requirements of NEPA. Certain federal permits on non-federal lands may also trigger NEPA requirements. This process has the potential to delay the development of oil and natural gas projects. Authorizations under NEPA also are subject to protest, appeal or litigation, which can delay or halt projects.

Waste Handling. The Resource Conservation and Recovery Act, or RCRA, and comparable state statutes affect oil and gas exploration and production activities by imposing regulations on the generation, transportation, treatment, storage, disposal and cleanup of “hazardous wastes” and on the disposal of non-hazardous wastes. Under the oversight of the Environmental Protection Agency, or EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Federal and state regulatory agencies can impose administrative penalties, civil and criminal judicial actions, as well as other enforcement mechanisms for non-compliance with RCRA or corresponding state programs. RCRA also imposes cleanup liability related to the mismanagement of regulated wastes. Drilling fluids, produced waters and most of the other wastes associated with the exploration, development and production of crude oil, natural gas, or geothermal energy are currently exempt from regulation under the hazardous waste provisions of RCRA, but there is no guarantee that the EPA or the individual states will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation, and legislation has been proposed from time to time in Congress to reverse the exemption. In addition, certain environmental groups petitioned and sued the EPA to

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reverse the exemption. The EPA entered into a consent decree with these environmental groups that committed the EPA to decide whether to revise its RCRA Subtitle D criteria regulations and state plan guidelines for the oil and natural gas sector. In April 2019 the EPA concluded that revisions to the federal regulations for the management of exploration, development and production wastes of crude oil, natural gas under Subtitle D of RCRA were not necessary. The EPA indicated that it will continue to work with states and other organizations to identify areas for continued improvement and to address emerging issues to ensure that exploration, development and production wastes continue to be managed in a manner that is protective of human health and the environment. Environmental groups, however, expressed dissatisfaction with the EPA’s decision and will likely continue to press the issue at the federal and state levels.

Although we believe that the current costs of managing our wastes as they are presently classified are reflected in our budget, any legislative or regulatory reclassification of oil and natural gas exploration and production wastes could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act, or CERCLA, also known as the “Superfund” law, imposes strict, joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be potentially responsible for a release or threatened release of a “hazardous substance” (generally excluding petroleum) into the environment. These persons may include current and past owners or operators of a disposal site, or site where the release or threatened release of a “hazardous substance” occurred, and companies that disposed of, transported or arranged for the disposal of the hazardous substance at such sites. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is not uncommon for neighboring landowners and other third parties to file claims under CERCLA and/or state common law for cleanup costs, personal injury and property damage allegedly caused by the hazardous substances released into the environment. In the course of our operations, we use materials that, if released, could be subject to CERCLA. Governmental agencies or third parties may seek to hold us responsible under CERCLA for all or part of the costs to clean up sites at which such “hazardous substances” have been released.

Water Discharges. The Federal Water Pollution Control Act, also known as the Clean Water Act (“CWA”), and analogous state laws impose restrictions and strict controls regarding the discharge of pollutants, including produced water, storm water drainage and other oil and gas wastes, into Waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or the state. These laws also prohibit the discharge of dredge and fill material in regulated waters, including jurisdictional wetlands, unless authorized under a permit issued by the U.S. Army Corps of Engineers (“Corps”). Federal and state regulatory agencies can impose administrative penalties, civil and criminal penalties, and take judicial action for non-compliance with discharge permits or other requirements of the federal CWA and analogous state laws and regulations. Obtaining permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, hence limiting the rate of development.

The EPA and the Corps finalized a federal rulemaking to revise the jurisdictional definition of “Waters of the United States” in June 2015. In February 2018, the EPA issued a rule that delays the applicability of the new definition of the waters of the United States, but this delay rule was struck following a court challenge. Other district courts, however, issued rulings temporarily enjoining the applicability of the 2015 definition of “Waters of the United States.” Taken together, the 2015 rule was in effect in 23 states, including Colorado, and temporarily stayed in the remaining states. On October 22, 2019, the EPA and the Corps published a final rule to repeal the 2015 rule defining Waters of the United States and re-codify the regulatory text that existed prior to the 2015 rule. This rule became effective on December 23, 2019. This was considered to be “Step One” by the EPA and the Corps. The “Step Two” rule is to implement a new definition of Waters of the United States. On January 23, 2020, the EPA and the Corps announced the final new rule, titled the Navigable Waters Protection Rule (“2020 Rule”). The 2020 Rule will go into effect sixty days after publication in the Federal Register. The 2020 Rule will generally regulate four categories of “jurisdictional” waters: (1) territorial seas and traditional navigable waters; (2) perennial and intermittent tributaries of these waters; (3) certain lakes, ponds, and impoundments; and (4) wetlands to jurisdictional waters. The 2020 Rule also includes 12 categories of exclusions, or “non-jurisdictional” waters, including groundwater, ephemeral features, and

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diffuse stormwater run-off over upland areas. In particular, the 2020 Rule will likely regulate fewer wetlands areas than were regulated under the prior definitions of “waters of the United States” because it does not regulate wetlands that are not adjacent to jurisdictional waters.    Following publication, this new definition of “waters of the United States” will likely be challenged and sought to be enjoined in federal court. Obtaining Clean Water Act permits has the potential to delay the development of oil and natural gas projects. These same regulatory programs may also limit the total volume of water or fill material that can be discharged, thus limiting the rate of development.

Air Emissions. The Federal Clean Air Act, and associated state laws and regulations, regulate emissions of various air pollutants through the issuance of permits, emission reporting, and the imposition of emission control requirements. Most of our facilities are now required to obtain permits before work can begin, and existing facilities are often required to incur additional capital costs in order to maintain compliance with new and evolving air quality laws and regulations. In 2012, the EPA issued new New Source Performance Standards (“NSPS”) and National Emission Standards for Hazardous Air Pollutants (“NESHAP”) specific to the oil and gas industry, including air standards for natural gas wells that are hydraulically fractured, and issued several amendments to the NSPS rules in 2013, 2014, 2015 and 2016, respectively. In addition, the EPA has deemed carbon dioxide (“CO2”) and other greenhouse gases, including methane, to be a danger to public health, which is leading to regulation of greenhouse gases in a manner similar to other pollutants. For example, the EPA finalized amendments to the NSPS rules in June 2016 that focused on methane emissions from the oil and gas industry in June 2016. The rules imposed, among other things, new requirements for leak detection and repair, control requirements for oil well completions, replacement of certain pneumatic pumps and controllers and additional control requirements for gathering, boosting and compressor stations. In September 2018, the EPA proposed revisions to the 2016 rules. The proposed amendments address certain technical issues raised in administrative petitions and include proposed changes to, among other things, the frequency of monitoring for fugitive emissions at well sites and compressor stations. On September 24, 2019 the EPA proposed reconsideration amendments to the NSPS that, among other things, would rescind the methane-specific requirements of the NSPS applicable to oil and gas production. The Bureau of Land Management (the “BLM”) also finalized similar methane and gas-capture rules for oil and gas operations on federal and tribal leases and certain committed state or private tracts in a federally approved unit or communitized agreement. In September 2018, the BLM published a final rule that revises the 2016 rules. The new rule, among other things, rescinds the 2016 rule requirements related to waste-minimization plans, gas-capture percentages, well drilling, well completion and related operations, pneumatic controllers, pneumatic diaphragm pumps, storage vessels, and leak detection and repair. The new rule also revised provisions related to venting and flaring. Environmental groups and the States of California and New Mexico have filed challenges to the 2018 rule in the United States District Court for the Northern District of California.

The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In 2014, 2017 and 2019, Colorado expanded its oil and gas air regulations, including the adoption of new and additional fugitive methane emission control regulations. In addition, in 2019 Colorado announced it’s intention to implement state-level greenhouse gas reporting rules in 2020. The first phase of that initiative, a new rule requiring oil and gas operators to submit an annual emission inventory, was approved on December 19, 2019 and will go into effect in 2020. The EPA has lowered the national ambient air quality standard (“NAAQS”) for ozone pollution, which may require the oil and gas industry to further reduce emissions of volatile organic compounds and nitrogen oxides. Colorado’s ozone non-attainment status was bumped-up from “marginal” to “moderate,” in early 2016 which triggered significant additional obligations for the State under the Clean Air Act and resulted in additional regulatory requirements for the oil and gas industry. On December 26, 2019 the EPA filed notice in the Federal Register that effective January 27, 2020 the Denver Metro/North Front Range NAA will be reclassified again to from “moderate” to “serious”. A “serious” classification triggers significant additional obligations for the state under the CAA and will result in new and more stringent air quality control requirements becoming applicable to our operations. this in turn could result in significant costs and delays in obtaining necessary permits. These state and federal regulations may increase the costs of compliance for some facilities we own or operate, and federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the Federal Clean Air Act and associated state laws and regulations.

Colorado SB 19-181 also requires, among other things, that the Air Quality Control Commission (“AQCC”) adopt additional rules to minimize emissions of methane and other hydrocarbons and nitrogen oxides from the entire oil and gas fuel cycle. The AQCC anticipates holding several rulemakings over the next several years to implement the requirements of SB 19-181,

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including a rulemaking to require continuous emission monitoring equipment at oil and gas facilities. In December 2019, the AQCC held the first of several rulemakings that are anticipated as a result of SB 19-181. As part of that rulemaking, the AQCC adopted significant additional and new emission control requirements applicable to oil and gas operations, including, for example, hydrocarbon liquids unloading control requirements and increased LDAR frequencies for facilities in certain proximity to occupied areas.

State-level rules applicable to our operations include regulations imposed by the AQCC, including stringent requirements relating to monitoring, recordkeeping and reporting matters. In October 2019, the Colorado Department of Public Health and Environment (“CDPHE”) published a human health risk assessment for oil and gas operations in Colorado, which used oil and gas emission data to model possible human exposure and found a possibility of negative health impacts at distances up to 2,000 feet away under worst case conditions. In response, the COGCC announced that it will more rigorously scrutinize permit applications for wells within 2,000 feet of a building unit, work with CDPHE to obtain better site-specific data on oil and gas emissions, and consider the resulting data for possible future rulemaking.

Hydraulic Fracturing. Our completion operations are subject to regulation, which may increase in the short or long-term. The well completion technique known as hydraulic fracturing is used to stimulate production of natural gas and oil and has come under increased scrutiny by the environmental community, as well as local, state and federal jurisdictions. Hydraulic fracturing involves the injection of water, sand and chemical additives under pressure into prospective rock formations at depth to stimulate oil and natural gas production. We use this completion technique on substantially all of our wells to obtain commercial production.

Under the direction of Congress, the EPA has undertaken a study of the effect, if any, of hydraulic fracturing on drinking water and groundwater and released its preliminary report in 2015, finding no systematic impact on groundwater resources. In its final report, issued in late 2016, EPA removed the conclusion of no systemic impact from the executive summary of the report, although it cited no new evidence to the contrary. In June 2016, the EPA finalized pretreatment standards for indirect discharges of wastewater from the oil and gas extraction industry. The regulation prohibits sending wastewater pollutants from onshore unconventional oil and gas extraction facilities to publicly-owned treatment works. In December 2016, the EPA released a report titled “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources.” The report concluded that activities involved in hydraulic fracturing can have impacts on drinking water under certain circumstances. These and similar studies, depending on their degree of development and nature of results obtained, could spur initiatives to further regulate hydraulic fracturing under the SDWA or other regulatory mechanisms. Congress may consider legislation to amend the SDWA or the Toxic Substances Control Act to require the disclosure of chemicals used by the oil and gas industry in the hydraulic fracturing process. Certain states, including Colorado, Utah and Wyoming, have already issued such disclosure rules. Several environmental groups have also petitioned the EPA to extend release reporting requirements under the Emergency Planning Community Right-to-Know Act to the oil and gas extraction industry and in 2015, EPA granted, in part, one of these petitions to add the oil and gas extraction industry to the list of industries required to report releases of certain “toxic chemicals” under the Toxic Release Inventory (“TRI”). On January 6, 2017, EPA issued a proposed rule to include natural gas processing facilities within the TRI program. In addition, the Department of the Interior finalized expanded or new regulations concerning the use of hydraulic fracturing on lands under its jurisdiction, which includes some of the lands on which we conduct or plan to conduct operations. The BLM rescinded the rule in December 2017; however, the BLM’s rescission has been challenged by several states in the United States District Court of the District of Northern California.

In Colorado, certain local jurisdictions imposed moratoria or bans on hydraulic fracturing, all of which have been invalidated, including on appeal to the Colorado Supreme Court. Senate Bill 19-181 subsequently authorized local jurisdictions to approve the siting of and regulate the surface impacts from oil and gas development and to adopt regulations and impose conditions more stringent than state requirements. It remains unclear whether local governments will attempt to use this new authority to restrict hydraulic fracturing or oil and gas development or whether such action would be lawful under SB 19-181 and Colorado Supreme Court precedent.

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Climate Change. In June 2014, the U.S. Supreme Court upheld a portion of the EPA’s greenhouse gas regulatory program for certain major sources in the Utility Air Regulatory Group v. EPA case. The EPA has finalized significant new rules to curb carbon emissions from power plants and other industrial activities, known as the Clean Power Plan, which in February 2016 was stayed by the U.S. Supreme Court. In March 2017, President Trump signed the Executive Order on Energy Independence which, among other things, called for a review of the Clean Power Plan. The EPA subsequently published a proposed rule to repeal the Clean Power Plan in October 2017. In August 2018, EPA proposed the Affordable Clean Energy (“ACE”) rule, which establishes emission guidelines for states to develop plans to address greenhouse gas emissions from existing coal-fired power plants. The ACE rule was finalized on June 19, 2019 and replaced the Clean Power Plan. Certain environmental groups are agitating for scaling back, or eliminating, fossil fuel extraction and use, including efforts to convince policy-makers that the majority of known oil and gas reserves must never leave the ground. These groups are mobilizing around a movement for global divestment from fossil fuel companies, which, if effective, could affect the market for our securities. In addition, in December 2015 the United States reached agreement during the United Nations climate change conference in Paris to make a 26-28% reduction in its greenhouse gas emissions by 2025 against a 2005 baseline. In June 2017, President Trump announced that the United States would initiate the formal process to withdraw from the Paris Agreement. Per the terms of the Paris Agreement, a country cannot give notice of withdrawal from the agreement before three years of its start date in the relevant country, which was on November 4, 2016 in the case of the United States. On November 4, 2019, President Trump’s administration gave a formal notice of intention to withdraw, which takes 12 months to take effect. Potential future laws, regulations or even litigation addressing greenhouse gas emissions could impact our business by limiting emissions of methane, restricting the flaring or venting of natural gas, or by reducing demand for oil or natural gas.

Homeland Security. Legislation continues to be introduced in Congress, and development of regulations continues in the Department of Homeland Security and other agencies, concerning the security of industrial facilities, including oil and natural gas facilities. Our operations may be subject to such laws and regulations but cost of compliance cannot be accurately estimated at this time.

Cybersecurity. Cybersecurity has been a topic of increased focus, and we have implemented several cybersecurity measures, including an emergency response plan, annual employee training, penetration tests, Supervisory Control and Data Acquisition (“SCADA”) protection and firewall upgrades. We have installed a comprehensive software package to track and document our cybersecurity initiatives which are reviewed by the Executive Committee and Board on a regular basis. Our cybersecurity initiatives are an increasingly important function of our Information Technology and Legal Departments. Presently, it is not possible to accurately estimate the costs we could incur to respond to a cyber attack, but such expenditures could be substantial.

Other Regulation of the Oil and Gas Industry

Our operations are subject to other types of regulation at federal, state and local levels. These types of regulation include requiring permits for the drilling of wells, bonds securing plugging, abandonment and reclamation obligations, and reports concerning our operations. Most states, and some counties and municipalities also regulate one or more of the following:

• the location of wells and surface facilities;

• the noise, traffic and light from the location;

• the method of drilling and casing wells;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• wildlife management and protection;

• the protection of archaeological and paleontological resources;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing well density and location, as well as the pooling of oil and natural gas properties. Some states provide statutory mechanisms for compulsory pooling or

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integration of tracts to facilitate exploration, while other states rely on voluntary pooling of lands and leases. In some instances, compulsory pooling or unitization may be implemented by third parties and subject our interest to third party operations. While not currently an issue in Colorado, other states establish maximum rates of production from oil and natural gas wells and impose requirements regarding ratable takes by purchasers of production. Such laws and regulations, if adopted in Colorado, might limit the amount of natural gas and oil we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, our production is generally subject to multiple layers of severance and/or ad valorem taxation by states, counties and special taxing districts.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production. The Federal Energy Regulatory Commission (“FERC”) has jurisdiction over the transportation and sale or resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 and the Natural Gas Policy Act of 1978. Since 1978, various federal laws have been enacted that have resulted in the complete removal of all price and non-price controls for “first sales” of domestic natural gas, which include all sales of our own production.

FERC also regulates interstate natural gas transportation rates and service conditions pursuant to the Natural Gas Act, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas. Commencing in 1985, FERC promulgated a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Interstate gas pipeline companies are required to provide nondiscriminatory, non-preferential transportation services to producers, marketers and other shippers regardless of whether such shippers are affiliated with an interstate pipeline company, and pursuant to such orders, regulations, and rules, interstate gas pipeline companies are required to file the tariff rates and other terms and conditions of such services with FERC.

The Energy Policy Act of 2005 (the “EPAct 2005”) was signed into law in August 2005. The EPAct 2005 amends the Natural Gas Act to make it unlawful for “any entity”, including otherwise non-jurisdictional producers, to use any deceptive or manipulative device or contrivance in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to regulation by FERC, in contravention of rules prescribed by FERC. The EPAct 2005 also gives FERC authority to impose civil penalties for violations of the Natural Gas Act or Natural Gas Policy Act up to $1 million per day per violation. The anti-manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales, gathering or production, but does apply to activities of otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” natural gas sales, purchases or transportation subject to FERC jurisdiction, thus reflecting a significant expansion of FERC’s enforcement authority.

FERC’s initiatives have led to the development of a competitive, unregulated, open access market for gas purchases and sales that permits all purchasers of gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, we cannot guarantee that the less stringent regulatory approach pursued by FERC and Congress over the past few decades will continue indefinitely into the future, nor can we determine what effect, if any, future regulatory changes may have on our natural gas-related activities.

Transportation and safety of natural gas is also subject to regulation by the U.S. Department of Transportation, through its Pipeline and Hazardous Materials Safety Administration, under the Natural Gas Pipeline Safety Act of 1968, as amended, which imposes safety requirements on the design, construction, operation, and maintenance of interstate natural gas transmission facilities, the Pipeline Inspection, Protection, Enforcement, and Safety Act of 2006 and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011. The failure to comply with these rules and regulations can result in substantial penalties.

Employees

As of February 4, 2020, we had 155 employees of whom 97 work in our Denver office and 58 work in our field offices. We also contract for the services of independent consultants involved in land, regulatory, accounting, financial and other disciplines as needed. None of our employees are represented by labor unions or covered by any collective bargaining agreement. We believe that our relations with our employees are good.

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Offices

As of December 31, 2019, we leased 79,279 square feet of office space for our principal office in Denver, Colorado at 555 17th Street, which expires in April 2028. Due to the Merger, we acquired 23,363 square feet of leased office space from Fifth Creek in Greenwood Village, Colorado, which extends through July 2023. We also own a field office in Greeley, Colorado and a field office in Hereford, Colorado. We believe that our facilities are adequate for our current operations and that we can obtain additional leased space if needed.

Annual CEO Certification

As required by New York Stock Exchange rules, on May 6, 2019 we submitted an annual certification signed by our Chief Executive Officer certifying that he was not aware of any violation by us of New York Stock Exchange corporate governance listing standards as of the date of the certification.

Item 1A. Risk Factors.

Our business involves a high degree of risk. If any of the following risks, or any risk described elsewhere in this Form 10-K, actually occurs, our business, financial condition or results of operations could suffer. The risks described below are not the only risks facing the Company. Additional risks not presently known to us or that we currently consider immaterial also may adversely affect our Company.

Risks Related to the Oil and Natural Gas Industry and Our Business

Oil and gas prices are volatile and changes in prices can significantly affect our financial results and estimated proved oil and gas reserves.

Our revenue, profitability and cash flow depend upon the prices for oil, natural gas and NGLs. The markets for these commodities are very volatile, based on supply and demand, and even relatively modest drops in prices can significantly affect our financial results and impede our growth. Changes in oil, natural gas and NGL prices have a significant impact on the value of our reserves and on our cash flow. Prices for oil, natural gas and NGLs may fluctuate widely in response to relatively minor changes in the supply of and demand for oil and gas, market uncertainty and a variety of additional factors that are beyond our control, such as:

• the global demand for oil, natural gas and NGLs;

• domestic and foreign governmental regulations;

• variations between product prices at sales points and applicable index prices;

• political and economic conditions in oil producing countries, including the Middle East and South America;

• the ability and willingness of members of the Organization of Petroleum Exporting Countries (“OPEC”) and other oil-producing countries to agree to and maintain oil price and production controls;

• weather conditions;

• technological advances affecting energy consumption;

• national and global economic conditions;

• proximity and capacity of oil and gas pipelines, refineries and other transportation and processing facilities;

• the price and availability of alternative fuels; and

• the strength of the U.S. dollar compared to other currencies.

Lower oil, natural gas and NGL prices may not only decrease our revenues on a per unit basis, but also may reduce the amount of oil, natural gas and NGLs that we can produce economically and therefore the quantity and the estimated present value of our reserves. If this occurs or if our estimates of development costs increase, production data factors change or our exploration or development results deteriorate, successful efforts accounting rules may require us to write down or impair, as a

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non-cash charge to earnings, the carrying value of our oil and natural gas properties. We are required to perform impairment tests on our assets whenever events or changes in circumstances lead to a reduction of the estimated useful life or estimated future cash flows that would indicate that the carrying amount may not be recoverable or whenever management’s plans change with respect to those assets.

Oil prices declined significantly in a number of recent periods, including the fourth quarter of 2018. Natural gas and NGL prices have also fallen significantly in some recent periods. These decreases have increased the volatility and amplitude of the other risks facing us as described in this report and have impacted our business and financial condition. If oil prices decrease from current levels, our planned drilling 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. Continued low commodity prices make it more challenging to hedge production at higher price levels.

Our drilling efforts and our well operations may not be profitable or achieve our targeted returns.

Drilling for oil, natural gas and NGLs may result in unprofitable efforts from wells that are productive but do not produce sufficient commercial quantities to cover drilling, operating and other costs. In addition, even a commercial well may have production that is less, or costs that are greater, than we projected. The cost of drilling, completing and operating a well is often uncertain, and many factors can adversely affect the economics of a well or property. Drilling operations may be curtailed, delayed or canceled as a result of unexpected drilling conditions, equipment failures or accidents, shortages of equipment or personnel, environmental issues, midstream constraints and for other reasons. We rely to a significant extent on seismic data and other advanced technologies in identifying unproved property prospects. The seismic data and other technologies we use do not allow us to know conclusively, prior to acquisition of unproved property or drilling a well, whether oil, natural gas or NGLs are present or may be produced economically. The use of seismic data and other technologies also requires greater pre-drilling expenditures than traditional drilling strategies. Drilling results in some of our plays may be more uncertain than in other plays that are more mature and have longer established drilling and production histories, and we can provide no assurance that drilling and completion techniques that have proven to be successful in other formations to maximize recoveries will be ultimately successful when used in our prospects. As a result, we may incur future dry hole costs and/or impairment charges due to any of these factors.

We have acquired significant amounts of proved and unproved property in order to attempt to further our exploration and development efforts. Drilling and production activities are subject to many risks, including the risk that no commercially productive reservoirs will be discovered. We acquire proved and unproved properties and lease undeveloped acreage that we believe will enhance our growth potential and increase our earnings over time. We cannot guarantee that all prospects will be economically viable or that we will not abandon our initial investments. Additionally, there can be no assurance that proved or unproved property acquired by us or undeveloped acreage leased by us will be profitably developed, that new wells drilled by us in prospects that we pursue will be productive, that we will recover all or any portion of our investment in such proved or unproved property or wells, or that we will succeed in bringing on additional partners.

Substantially all of our producing properties are located in the DJ Basin, making us vulnerable to risks associated with operating in one major geographic area.

Our operations are focused on the DJ Basin, which means our current producing properties and new drilling opportunities are geographically concentrated in that area. Because our operations are not as diversified geographically as many of our competitors, the success of our operations and our profitability may be disproportionately exposed to the effect of any regional events, including fluctuations in prices of oil, natural gas and NGLs produced from the wells in the region, natural disasters, restrictive governmental regulations, transportation capacity constraints, weather, curtailment of production or interruption of transportation and processing, and any resulting delays or interruptions of production from existing or planned new wells.

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We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, manner or feasibility of doing business and the recording of proved reserves. Changes in the regulatory environment could have a material adverse effect on our business.

Our exploration, development, production and marketing operations are subject to extensive environmental regulation at the federal, state and local levels including those governing emissions to air, wastewater discharges, hazardous and solid wastes, remediation of contaminated soil and groundwater, protection of surface and groundwater, land reclamation and preservation of natural resources. Under these laws and regulations, we could be held liable for personal injuries, property damage (including site clean-up and restoration costs) and other damages. Failure to comply with these laws and regulations may also result in the suspension or termination of our operations and subject us to administrative, civil, and criminal penalties, including the assessment of natural resource damages. Environmental and other governmental laws and regulations also increase the costs to plan, permit, design, drill, install, operate and abandon oil and natural gas wells and related facilities. Moreover, public interest in environmental protection has increased in recent years, and environmental organizations have opposed, with some success, certain drilling projects, leading to delays.

The regulatory environment in which we operate is subject to frequent changes, often in ways that increase our costs and make it more difficult for us to obtain necessary permits in a timely manner. See “Business and Properties-Operations-Environmental Matters and Regulation” for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.

Our success depends on key members of our management and our ability to attract and retain experienced technical and other professional personnel.

Our future success depends to a large extent on the services of our key employees. The loss of one or more of these individuals could have a material adverse effect on our business. Furthermore, competition for experienced technical and other professional personnel remains strong. If we cannot retain our current personnel or attract additional experienced personnel, our ability to compete could be adversely affected. Also, the loss of experienced personnel could lead to a loss of technical expertise.

Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.

Market conditions or the unavailability of satisfactory oil and natural gas transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil, natural gas and NGL production depends on a number of factors, including the demand for and supply of oil and natural gas and the proximity of our reserves to pipelines and terminal facilities. Our ability to market our production depends in substantial part on the availability and capacity of gathering systems, pipelines, processing facilities and refineries owned and operated by third parties. We may be required to shut in wells for a lack of a market or because of inadequacy or unavailability of natural gas pipeline, gathering system capacity or processing facilities. If that were to occur, we would be unable to realize revenue from those wells until production arrangements were made to deliver the production to market.

We may incur substantial losses and be subject to substantial liability claims as a result of our oil and gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.

We are not insured against all risks. Losses and liabilities arising from uninsured or under-insured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

• environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

• abnormally pressured or structured formations;

• mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;

• fires, explosions and ruptures of pipelines;

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• personal injuries and death; and

• natural disasters.

Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:

• injury or loss of life;

• damage to and destruction of property and equipment;

• damage to natural resources due to underground migration of hydraulic fracturing fluids or other fluids or gases;

• pollution and other environmental damage, including spillage or mishandling of recovered hydrocarbons, hydraulic fracturing fluids and produced water;

• regulatory investigations and penalties;

• suspension of our operations; and

• repair and remediation costs.

We have elected, and may in the future elect, not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. For example, we do not carry business interruption insurance for these reasons. In addition, pollution and environmental risks generally are not fully insurable. Further, we could be unaware of a pollution event when it occurs and therefore be unable to report the event within the time period required under the relevant policy. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations and overall financial condition.

Our operations require substantial capital and we may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a loss of properties and a decline in our oil, natural gas and NGL reserves.

The oil and gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business and operations for the development, production and acquisition of oil, natural gas and NGL reserves. To date, we have financed capital expenditures primarily with cash generated by operations, sales of our equity and debt securities, proceeds from bank borrowings and sales of properties. Our cash flow from operations and access to capital is subject to a number of variables, including:

• our proved reserves;

• the level of oil, natural gas and NGLs we are able to produce from existing wells;

• the prices at which oil, natural gas and NGLs are sold;

• the costs required to operate production;

• our ability to acquire, locate and produce new reserves;

• global credit and securities markets;

• the ability and willingness of lenders and investors to provide capital and the cost of that capital; and

• the interest of buyers in our properties and the price they are willing to pay for properties.

If our revenues or the borrowing base under our Amended Credit Facility decreases as a result of lower oil, natural gas and NGLs prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. We may, from time to time, need to seek additional financing. Our Amended Credit Facility and senior note indentures place certain restrictions on our ability to obtain new financing. There can be no assurance as to the availability or terms of any additional financing. Recent commodity price decreases have made it substantially more difficult for us and other industry participants to raise capital, and will likely have an adverse effect on our borrowing base.

If additional capital is needed, we may not be able to obtain debt or equity financing on terms favorable to us, or at all. If the cash generated by operations or the amount available under our Amended Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to exploration and development of our prospects, which in turn could lead to a possible loss of properties and a decline in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.

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Our identified drilling location inventories are scheduled out over several years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

Our management has specifically identified and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These identified drilling locations represent a significant part of our strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including the availability of capital, seasonal conditions, regulatory approvals, oil, natural gas and NGLs prices, costs and drilling results. Because of these uncertainties, we do not know if the numerous potential drilling locations we have identified will ever be drilled or if we will be able to produce oil, natural gas and NGLs from these or any other potential drilling locations. As such, our actual drilling activities may differ materially from those presently identified, which could adversely affect our business.

Competition in the oil and gas industry is intense, which may adversely affect our ability to succeed.

The oil and gas industry is intensely competitive, and we compete with other companies that have greater resources. Many of these companies not only explore for, develop and produce oil, natural gas and NGLs, but also carry on midstream and refining operations and market petroleum and other products on a regional, national or worldwide basis. These companies are able to pay more for producing oil, natural gas and NGLs properties and exploration and development prospects or define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. In addition, these companies have a greater ability to continue exploration activities during periods of low oil, natural gas and NGLs market prices. Our larger or integrated competitors are better able than we are to absorb the burden of existing and any changes to federal, state, local and Native American tribal laws and regulations, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. In addition, because we have fewer financial resources than many companies in our industry, we may be at a disadvantage in bidding for producing properties and exploration and development prospects.

The willingness and ability of our lenders to fund their lending obligations under our revolving Amended Credit Facility may be limited, which would affect our ability to fund our operations.

Our Amended Credit Facility has commitments from 11 lenders. If credit markets become turbulent as a result of an economic downturn, increased regulatory oversight, lower commodity prices or other factors, our lenders may become more restrictive in their lending practices or may be unwilling or unable to fund their commitments, which would limit our access to capital to fund our capital expenditures, operations or meet other obligations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and potentially losses.

A U.S. and global economic downturn could have a material adverse effect on our business and operations.

Any or all of the following may occur if, as a result of a crisis in the global financial and securities markets, a deterioration in national or global growth prospects or other factors, an economic downturn occurs:

• The economic slowdown could lead to lower demand for oil and natural gas by individuals and industries, which in turn could result in lower prices for the oil and natural gas sold by us, lower revenues and possibly losses. Significant recent commodity price declines have been caused in part by concerns about future global economic growth. This factor has at times been exacerbated by increases in oil and gas supply resulting from increases in U.S. oil and gas production.

• The lenders under our Amended Credit Facility may become more restrictive in their lending practices or unable or unwilling to fund their commitments, which would limit our access to capital to fund our capital expenditures and operations. This would limit our ability to generate revenues as well as limit our projected production and reserves growth, leading to declining production and possibly losses.

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• We may be unable to obtain additional debt or equity financing, which would require us to limit our capital expenditures and other spending. This would lead to lower production levels and reserves than if we were able to spend more than our cash flow. Financing costs may significantly increase as lenders may be reluctant to lend without receiving higher fees and spreads.

• The losses incurred by financial institutions and the insolvency of some financial institutions heightens the risk that a counterparty to our hedge arrangements could default on its obligations. These losses and the possibility of a counterparty declaring bankruptcy or being placed in conservatorship or receivership may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving a lower price for our natural gas and oil sales. As a result, our financial condition could be materially adversely affected.

• Our credit facility bears floating interest rates based on the London Interbank Offer Rate (“LIBOR”). As banks were reluctant to lend to each other to avoid risk, LIBOR increased to unprecedented spread levels in 2008. Such increases caused and may in the future cause higher interest expense for unhedged levels of LIBOR-based borrowings. In addition, LIBOR may be eliminated in the near future as a reference index for determining interest rates under credit arrangements. The elimination of LIBOR may cause us to incur increased interest expense.

• Our credit facility requires the lenders to redetermine our borrowing base semi-annually. The redeterminations are based on our proved reserves and hedge position based on price assumptions that our lenders require us to use to calculate reserves pursuant to the credit facility. The lenders could reduce their price assumptions used to determine reserves for calculating our borrowing base due to lower commodities and futures prices and our borrowing base could be reduced. This would reduce our funds available to borrow. In addition, the lenders can request an interim redetermination during each six month period which could reduce the funds available to borrow under our credit facility.

• Bankruptcies of financial institutions or illiquidity of money market funds may limit or delay our access to our cash and cash equivalent deposits, causing us to lose some or all of those funds or to incur additional costs to borrow funds needed on a short-term basis that were previously funded from our money market deposits.

• Bankruptcies of purchasers of our oil and natural gas could lead to the delay or failure of us to receive the revenues from those sales.

Our estimated reserves are based on many assumptions that may turn out to be inaccurate. Any material inaccuracies in these assumptions will materially affect the quantities of our reserves.

Underground accumulations of oil, natural gas and NGLs cannot be measured in an exact way. Oil, natural gas and NGLs reserve engineering requires estimates of underground accumulations of oil, natural gas and NGLs and assumptions concerning future oil, natural gas and NGLs prices, production levels and operating and development costs. As a result, estimated quantities of proved reserves and projections of future production rates and the timing of development expenditures may be inaccurate.

Our estimates of proved reserves are based on prices and costs determined at the date of the estimate. Any significant variance from these prices and costs could greatly affect our estimates of reserves. We prepare our own estimates of proved reserves, which are audited by independent third party petroleum engineers. Over time, our internal engineers may make material changes to reserves estimates taking into account the results of actual drilling, testing and production. For additional information about these risks and their impact on our reserves, see “Items 1 and 2. Business and Properties-Oil and Gas Data-Proved Reserves” and “Supplementary Information to Consolidated Financial Statements-Supplementary Oil and Gas Information (unaudited)-Analysis of Changes in Proved Reserves” in this Annual Report on Form 10-K.

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At December 31, 2019, approximately 59% of our estimated proved reserves (by volume) were undeveloped. These reserve estimates reflect our plans to make significant capital expenditures to convert our PUDs into proved developed reserves, including approximately $1.2 billion during the five years ending December 31, 2024. The estimated development costs may not be accurate, development may not occur as scheduled and results may not be as estimated. If we choose not to develop PUDs, or if we are not otherwise able to successfully develop them, we will be required to remove the associated volumes from our reported proved reserves. In addition, under the SEC’s reserve reporting rules, PUDs generally may be booked only if they relate to wells scheduled to be drilled within five years of the date of booking, and we may therefore be required to downgrade to probable or possible any PUDs that are not developed within this five-year time frame.

Unless we replace our oil, natural gas and NGLs reserves, our reserves and production will decline, which would adversely affect our business, financial condition and results of operations.

Producing oil, natural gas and NGL reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. The rate of decline may be different than we have estimated and may change over time. Our future oil, natural gas and NGL reserves and production, and therefore our cash flow and income, are highly dependent upon our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire additional reserves to replace our current and future production at acceptable costs.

Properties that we buy may not produce as projected and we may be unable to determine reserve potential, identify liabilities associated with the properties or obtain protection from sellers.

One of our strategies is to capitalize on opportunistic acquisitions of oil, natural gas and NGLs reserves. Our reviews of acquired properties are inherently incomplete, because it generally is not feasible to review in depth every individual property involved in each acquisition. Ordinarily, we will focus our review efforts on the higher value properties and will sample the remaining properties for reserve potential. However, even a detailed review of records and properties may not necessarily reveal existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to assess fully their deficiencies and potential. Inspections may not always be performed on every well, and environmental problems, such as ground water contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, we often assume certain environmental and other risks and liabilities in connection with acquired properties.

Our hedging activities could result in financial losses or could reduce our income.

To achieve a more predictable cash flow and to reduce our exposure to adverse fluctuations in the prices of commodities, we currently, and will likely in the future, enter into hedging arrangements for a portion of our production revenues. Hedging arrangements for a portion of our production revenues expose us to the risk of financial loss in some circumstances, including when:

• there is a change in the expected differential between the underlying price in the hedging agreement and actual prices received;

• our production is less than we expect;

• there is a change in the mark to market value of our derivatives; or

• the counterparty to the hedging contract defaults on its contractual obligations.

In addition, these types of hedging arrangements limit the benefit we would receive from increases in commodities prices and may expose us to cash margin requirements if we hedge with counterparties who are not parties to our credit facility.

Our counterparties are financial institutions that are lenders under our Amended Credit Facility or affiliates of such lenders. The risk that a counterparty may default on its obligations increases when overall economic conditions deteriorate. Losses resulting from adverse economic conditions or other factors may affect the ability of the counterparties to meet their obligations to us on hedge transactions, which could reduce our revenues from hedges at a time when we are also receiving lower prices for our production. As a result, our financial condition could be materially adversely affected.

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Federal legislation may decrease our ability, and increase the cost, to enter into hedge transactions.

The Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank”) was signed into law in July 2010. Dodd-Frank regulates derivative transactions, including our commodity derivative swaps. We expect that Dodd-Frank and its implementing regulations will increase the cost to hedge as a result of fewer counterparties being in the market and the pass-through of increased capital costs of bank subsidiaries. The imposition of margin requirements or other restrictions on our hedging activities could make hedging more expensive or impracticable. A reduction in our ability to enter into hedging transactions would expose us to additional risks related to commodity price volatility and impair our ability to have certainty with respect to a portion of our cash flow, which could lead to decreases in capital spending and, therefore, decreases in future production and reserves.

The inability of one or more of our customers to meet their obligations may adversely affect our financial results.

Substantially all of our accounts receivable result from oil, natural gas and NGLs sales or joint interest billings to third parties in the energy industry. This concentration of customers and joint interest owners may impact our overall credit risk in that these entities may be similarly affected by changes in economic and other conditions. In addition, our oil, natural gas and NGLs hedging arrangements expose us to credit risk in the event of nonperformance by counterparties. An economic downturn and/or an extended period of low commodity prices would increase these risks.

We face risks related to rating agency downgrades.

If one or more rating agencies downgrades our outstanding debt, future debt issuance could become more difficult and costly. Also, we may be required to provide collateral or other credit support to certain counterparties, which would increase our costs and limit our liquidity.

Our business could be negatively impacted by security threats, including cyber-security threats, and other disruptions.

As an oil and natural gas producer, we face various security threats, including cyber-security threats to gain unauthorized access to sensitive information, acquire cash or other assets through theft or fraud or render data or systems unusable, threats to the safety of our employees, threats to the security of our facilities and infrastructure or third party facilities and infrastructure, such as processing plants and pipelines, and threats from terrorist acts. Cyber-security attacks in particular are evolving and include but are not limited to, malicious software, attempts to gain unauthorized access to data, and other electronic security breaches that could lead to disruptions in critical systems, unauthorized release of confidential or otherwise protected information, corruption of data or misappropriation of assets. There can be no assurance that the procedures and controls we use to monitor and mitigate these risks will be sufficient in preventing security threats from materializing. If any of these events were to materialize, they could lead to losses of sensitive information, assets, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial position, results of operations, or cash flows.

Land owner demands associated with previously divested wells in Wyoming could have adverse effects on our business.

In December 2015, the Wyoming Supreme Court issued its “Pennaco” decision, the essence of which is that parties to a contract, such as a surface use agreement, remain liable for the obligations under that agreement—even when the agreement and the underlying assets have been sold and assigned to a third party—unless the agreement contains express language releasing and discharging the original party upon such subsequent assignment.

Landowners across Wyoming are making Pennaco claims against companies that sold assets to other oil and gas companies that are now in default. To date, our exposure relates to coalbed methane (“CBM”) leases and wells that we sold to entities

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which are now essentially defunct, if not in actual bankruptcy proceedings. These operators have defaulted on several annual surface use payments, as well as leaving more than 150 CBM wells acquired from us in non-producing (shut-in) status. We have been contacted by several large ranches or their attorneys demanding payment of amounts in arrears, and that we conduct the plugging of the wells and land reclamation. Each case entails determining what contractual obligations are imposed by the applicable surface use agreement, taking into account state and federal plugging and reclamation requirements.

We obtained orders from the Wyoming Oil & Gas Conservation Commission (“WOGCC”) requiring two of the defaulting operators to “show cause” as to why the WOGCC should not authorize us to take over the wells in order to conduct plugging and reclamation operations. In response to these orders, we reached contractual agreements that provide us with the authority to plug and abandon any or all of the wells sold to those operators. We have negotiated settlement and release agreements with several ranches that require payments and scheduled plugging and reclamation activities. In certain cases, ranch owners have expressed interest in conversion of CBM wells to water wells. We are under no current WOGCC compulsion to plug wells. A substantial number of wells are federally-permitted, and the Company and the BLM have recently negotiated a plugging and reclamation schedule for these wells. During 2019, the Company plugged 53 wells and 3 wells were converted to water wells by the landowner. In 2020, the Company plans to plug and abandon an additional 65 wells.

We do not believe that resolving this matter will have a material financial impact. We believe that, if necessary, the currently identified roster of shut-in wells can be plugged and reclaimed at cost of approximately $15,000 per well. There is no assurance, however, that this issue will not expand to wells sold to other purchasers of Wyoming assets previously owned by us.

Risks Related to Our Common Stock

If we cannot regain compliance with the NYSE’s continued listing standards, 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.

On November 4, 2020, the Company received a notice from the NYSE that it is no longer in compliance with the NYSE continued listing standards set forth in Section 802.01B of the NYSE’s Listed Company Manual due to the fact that the Company’s average global market capitalization over a consecutive 30 trading-day period was less than $50 million and, at the same time, its stockholders’ equity was less than $50 million. In accordance with the NYSE listing requirements, we will submit a plan that demonstrates how we expect to return to compliance with NYSE listing standard 802.01B by the deadline of December 19, 2020. If the NYSE accepts the plan and we are unable to comply with the plan, or if we are unable to meet the continued listing standard within 18 months of receipt of the notice, we will be subject to the prompt initiation of NYSE suspension and delisting procedures. 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.

Provisions in our certificate of incorporation and bylaws and Delaware law make it more difficult to effect a change in control of us, which could adversely affect the price of our common stock.

Delaware corporate law and our current certificate of incorporation and bylaws contain provisions that could delay, defer or prevent a change in control of us or our management. These provisions include:

• giving the board the exclusive right to fill all board vacancies;

• requiring special meetings of stockholders to be called only by the board;

• requiring advance notice for stockholder proposals and director nominations;

• prohibiting stockholder action by written consent;

• prohibiting cumulative voting in the election of directors; and

• allowing for authorized but unissued common and preferred shares.

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These provisions also could discourage proxy contests and make it more difficult for our stockholders to elect directors and take other corporate actions that are opposed by our board. As a result, these provisions could make it more difficult for a third party to acquire us, even if doing so would benefit our stockholders, and this may limit the price that investors are willing to pay in the future for shares of our common stock.

Risks Related to our Senior Notes and Amended Credit Facility

We may not be able to generate enough cash flow to meet our debt obligations, including our obligations and commitments under our senior notes and our Amended Credit Facility.

We expect that our earnings and cash flow could vary significantly from year to year due to the cyclical nature of our industry. As a result, the amount of debt that we can manage in some periods may not be appropriate for us in other periods. In addition, our future cash flow may be insufficient to meet our debt obligations and commitments, including our 7.0% Senior Notes due 2022 (“7.0% Senior Notes”), 8.75% Senior Notes due 2025 (“8.75% Senior Notes”) and our Amended Credit Facility. Any insufficiency could negatively impact our business. A range of economic, competitive, business, and industry factors will affect our future financial performance, and, as a result, our ability to generate cash flow from operations and to repay our debt. Many of these factors, such as oil and gas prices, economic and financial conditions in our industry and the global economy or competitive initiatives of our competitors, are beyond our control. In particular, these risks have been significantly exacerbated by the sustained decline in commodity prices.

As of December 31, 2019, the total outstanding principal amount of our indebtedness was $765.0 million, and we had $334.0 million in additional borrowing capacity under our Amended Credit Facility, which, if borrowed, would be secured debt effectively senior to the Senior Notes to the extent of the value of the collateral securing that indebtedness. The borrowing base is dependent on our proved reserves and was, as of December 31, 2019, $500.0 million based on our proved reserves and hedge position. Our borrowing capacity is reduced by a $26.0 million letter of credit. As of December 31, 2019, we had $140.0 million outstanding under our Amended Credit Facility.

The borrowing base is set at the sole discretion of the lenders. Our next scheduled borrowing base redetermination is scheduled on or about April 1, 2020 based on proved reserves as of December 31, 2019 at updated bank price decks and hedge position. However, in the event of lower capital investment in our properties due to a sustained cycle of low commodity prices, we could see lower quantities of proved developed reserves which would, in combination with lower oil and gas commodity pricing, lead to lower borrowing bases.

If we do not generate enough cash flow from operations to satisfy our debt obligations, we may have to undertake one or more alternative financing plans, such as:

• refinancing or restructuring our debt;

• selling assets;

• reducing or delaying capital investments; or

• seeking to raise additional capital.

However, any alternative financing plans that we undertake may not be completed in a timely manner or at all, and even if completed may not allow us to meet our debt obligations. Our inability to generate sufficient cash flow to satisfy our debt obligations, including our obligations under the senior notes, or to obtain alternative financing, could materially and adversely affect our business, financial condition, results of operations and prospects.

Our debt could have important consequences. For example, it could:

• increase our costs of doing business;

• increase our vulnerability to general adverse economic and industry conditions;

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• limit our ability to fund future capital expenditures and working capital, to engage in future acquisitions or development activities, or to otherwise realize the value of our assets and opportunities fully because of the need to dedicate a substantial portion of our cash flow from operations to payments of interest and principal on our debt or to comply with any restrictive terms of our debt;

• limit our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• impair our ability to obtain additional financing in the future; and

• place us at a competitive disadvantage compared to our competitors that have less debt.

We may be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive covenants under the indentures governing the senior notes and our Amended Credit Facility impose on us.

The Amended Credit Facility also contains certain financial covenants. We are currently in compliance with all financial covenants and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on our 2020 budget at current commodity prices. However, if commodity prices significantly decline, EBITDAX will be significantly reduced, which is a critical underpinning of our required financial covenants. If this were to occur, it will make it necessary for us to negotiate an amendment to one or more of these financial covenants.

If we fail to comply with the covenants or other terms of any agreements governing our debt, our lenders and holders of our notes may have the right to accelerate the maturity of that debt and foreclose upon the collateral, if any, securing that debt. If that occurs, we may not be able to make all of the required payments or borrow sufficient funds to refinance such debt or take other actions to pay the accelerated debt. Even if new financing were available at that time, it may not be on terms that are acceptable to us. A breach of any covenant would also limit the funds available under our Amended Credit Facility. In September 2015, we obtained an amendment to the Amended Credit Facility that replaced our debt-to-EBITDAX covenant in the facility for a limited period of time. Through March 31, 2018, the covenants are secured debt-to-EBITDAX and EBITDAX-to-interest. There can be no assurance that we will be able to obtain similar amendments, or waivers of covenant breaches, in the future if needed.

Risks Related to Tax

We may incur more taxes as a result of new tax legislation.

The Tax Cut and Jobs Act (the “TCJA”) was passed in December 2017 and included provisions that could limit certain tax deductions:

• interest expense is limited to 30% of our taxable income (with certain adjustments);

• expanded Section 162(m) limitations on the deductibility of officers’ compensation; and

• net operating losses (“NOL”) incurred after 2017 are limited to 80% of taxable income but can be carried forward indefinitely.

These changes may increase our future tax liability in some circumstances. In addition, proposals are made from time to time to amend U.S. federal and state income tax laws in ways that would be adverse to us, including by eliminating certain key U.S. federal income tax preferences currently available with respect to crude oil and natural gas exploration and production. The changes could include (i) the repeal of the percentage depletion deduction for crude oil and natural gas properties, (ii) the elimination of current deductions for intangible drilling and development costs and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Also, state severance taxes may increase in the states in which we operate. This could adversely affect our existing operations in the relevant state and the economic viability of future drilling.

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Our future utilization of NOLs and tax credit carryforwards have been limited by the Merger and may be further limited based on current Internal Revenue Code restrictions.

We have significant deferred tax assets for Federal and state NOL carryforwards. Subject to certain limitations and applicable expiration dates, these tax attributes can be carried forward to reduce our federal income tax liability for future periods. Under Section 382 of the Internal Revenue Code of 1986, as amended (the “Code”), the ability to utilize NOL carryforwards to offset future taxable income is subject to limitation if a greater than 50% ownership change occurs (“Section 382 change of ownership”). A Section 382 change of ownership refers to an increase in ownership of more than 50% of our shares by certain groups of shareholders during any three-year period, as determined under certain conventions.

The Merger resulted in a Section 382 change of ownership, limiting our ability to use pre-change NOLs and credits against post-change taxable income to an annual limitation amount plus certain built-in gains recognized within five years of the ownership change (“RBIG”). The annual limitation amount of $11.7 million was computed by multiplying our fair market value on the date of the ownership change by a published long-term tax-exempt bond rate. Our RBIG is projected to be $176.9 million. We have reduced our federal and state NOLs by $276.1 million and $14.0 million, respectively, and eliminated our state tax credits by $8.2 million to reflect the expected impact of the Section 382 change of ownership. Deferred tax assets and the corresponding valuation allowance have been reduced by $65.0 million for the expected tax-effected impact of the Section 382 change of ownership.

Item 1B. Unresolved Staff Comments.

None.

Item 3. Legal Proceedings.

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

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

Item 4. Mine Safety Disclosures.

Not applicable.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market for Registrant’s Common Equity

Our common stock is listed on the New York Stock Exchange under the symbol “HPR”.

Holders. On February 4, 2020, there were 91 holders of record of our common stock.

Dividends. We have not paid any cash dividends since our inception. Because we anticipate that all earnings will be retained for the development of our business and our debt agreements limit the payment of cash dividends, we do not expect that any cash dividends will be paid on our common stock for the foreseeable future.

Unregistered Sales of Securities. There were no sales of unregistered equity securities during the year ended December 31, 2019.

Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 2019 (as adjusted for the impact of the 1-for-50 reverse stock split effected on October 30, 2020):

Period	Total Number of Shares Purchased (1)		Weighted Average Price Paid Per Share		Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs		Maximum Number (or Approximate Dollar Value) of Shares that May Yet be Purchased Under the Plans or Programs
October 1 - 31, 2019		22	$	57.50		—		—
November 1 - 30, 2019		44	$	64.00		—		—
December 1 - 31, 2019		—	$	—		—		—
Total		66	$	62.00		—		—

(1) Represents shares withheld from employees to satisfy tax withholding obligations in connection with the vesting of shares of restricted common stock issued pursuant to our employee incentive plans.

Stockholder Return Performance Presentation

As required by applicable rules of the SEC, the performance graph shown below was prepared based upon the following assumptions:

1. $100 was invested in our common stock on December 31, 2014, and $100 was invested in each of the Standard & Poors SmallCap 600 Index-Energy Sector and the Standard & Poors 500 Index at the closing price on December 31, 2014.

2. Dividends are reinvested on the ex-dividend dates.

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	December 31, 2014		December 31, 2015		December 31, 2016		December 31, 2017		December 31, 2018		December 31, 2019
HPR	$	100	$	35	$	61	$	45	$	22	$	15
S&P SmallCap 600- Energy		100		53		73		54		31		26
S&P 500		100		101		114		138		132		174

Item 6. Selected Financial Data.

The following table presents our selected historical financial data for the years ended December 31, 2019, 2018, 2017, 2016 and 2015. Future results may differ substantially from historical results because of changes in oil and gas prices, production increases or declines, properties acquired or sold and other factors. This information should be read in conjunction with the consolidated financial statements and notes thereto and “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” presented elsewhere in this Annual Report on Form 10-K.

Selected Historical Financial Information

The consolidated statement of operations information for the years ended December 31, 2019, 2018 and 2017 and the balance sheet information as of December 31, 2019 and 2018 are derived from our audited consolidated financial statements included elsewhere in this report. The consolidated statement of operations information for the years ended December 31, 2016 and 2015 and the balance sheet information at December 31, 2017, 2016 and 2015 are derived from audited consolidated financial statements that are not included in this report. The information in this table should be read in conjunction with the consolidated financial statements and accompanying notes and other financial data included herein.

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	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in thousands, except per share data)
Statement of Operations Data:
Operating Revenues
Oil, gas and NGL production	$	452,274		$	452,917		$	251,215		$	178,328		$	204,537
Other operating revenues, net		385			100			1,624			491			3,355
Total operating revenues		452,659			453,017			252,839			178,819			207,892
Operating Expenses
Lease operating expense		37,796			27,850			24,223			27,886			42,753
Gathering, transportation and processing expense		10,685			4,644			2,615			2,365			3,482
Production tax expense		23,541			36,762			14,476			10,638			12,197
Exploration expense		143			70			83			83			153
Impairment and abandonment expense		9,642			719			49,553			4,249			575,310
(Gain) loss on sale of properties		2,901			1,046			(92	)		1,078			1,745
Depreciation, depletion and amortization		321,276			228,480			159,964			171,641			205,275
Unused commitments		17,706			18,187			18,231			18,272			19,099
General and administrative expense (1)		44,759			45,130			42,476			42,169			53,890
Merger transaction expense		4,492			7,991			8,749			—			—
Other operating expenses, net		402			1,273			(1,514	)		(316	)		—
Total operating expenses		473,343			372,152			318,764			278,065			913,904
Operating Income (Loss)		(20,684	)		80,865			(65,925	)		(99,246	)		(706,012	)
Other Income and Expense:
Interest and other income		791			1,793			1,359			235			565
Interest expense		(58,100	)		(52,703	)		(57,710	)		(59,373	)		(65,305	)
Commodity derivative gain (loss)		(98,953	)		93,349			(9,112	)		(20,720	)		104,147
Gain (loss) on extinguishment of debt		—			(257	)		(8,239	)		8,726			1,749
Total other income (expense)		(156,262	)		42,182			(73,702	)		(71,132	)		41,156
Income (Loss) before Income Taxes		(176,946	)		123,047			(139,627	)		(170,378	)		(664,856	)
(Provision for) Benefit from Income Taxes		42,116			(1,827	)		1,402			—			177,085
Net Income (Loss)	$	(134,830	)	$	121,220		$	(138,225	)	$	(170,378	)	$	(487,771	)
Income per common share:
Basic (2)	$	(32.04	)	$	32.19		$	(89.92	)	$	(153.77	)	$	(504.94	)
Diluted (2)	$	(32.04	)	$	32.03		$	(89.92	)	$	(153.77	)	$	(504.94	)
Weighted average common shares outstanding, basic (2)		4,208			3,766			1,537			1,108			966
Weighted average common shares outstanding, diluted (2)		4,208			3,785			1,537			1,108			966

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million, $7.2 million, $8.3 million, $11.9 million and $10.8 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.

(2) All share and per share amounts were retroactively adjusted for all periods presented to give effect to the 1-for-50 reverse stock split effective October 30, 2020. See Note 16 to the Consolidated Financial Statements for additional information.

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	Year Ended December 31,
	2019			2018			2017			2016			2015
	(in thousands)
Selected Cash Flow and Other Financial Data:
Net income (loss)	$	(134,830	)	$	121,220		$	(138,225	)	$	(170,378	)	$	(487,771	)
Depreciation, depletion, impairment and amortization		325,130			228,480			209,062			171,824			777,713
Other non-cash items		90,055			(126,385	)		45,603			124,552			(83,760	)
Change in assets and liabilities		(1,720	)		8,126			5,550			(4,262	)		(12,504	)
Net cash provided by operating activities	$	278,635		$	231,441		$	121,990		$	121,736		$	193,678
Capital expenditures (1)	$	361,005		$	508,908		$	260,659		$	98,292		$	287,411

(1) Includes exploration and abandonment expense, which are expensed under successful efforts accounting, of $5.9 million, $0.8 million, $0.5 million, $4.1 million and $3.0 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively. Also includes furniture, fixtures and equipment costs of $4.6 million, $0.7 million, $1.0 million, $1.1 million and $1.3 million for the years ended December 31, 2019, 2018, 2017, 2016 and 2015, respectively.

	As of December 31,
	2019		2018		2017		2016		2015
	(in thousands)
Balance Sheet Data:
Cash and cash equivalents	$	16,449	$	32,774	$	314,466	$	275,841	$	128,836
Other current assets		69,988		157,007		53,197		42,611		145,481
Oil and natural gas properties, net of accumulated depreciation, depletion, amortization and impairment		2,043,447		2,020,873		1,012,610		1,055,049		1,160,898
Other property and equipment, net of depreciation		20,727		8,650		6,270		7,100		9,786
Other assets (1)		5,441		33,156		4,163		4,740		61,519
Total assets	$	2,156,052	$	2,252,460	$	1,390,706	$	1,385,341	$	1,506,520
Current liabilities	$	175,478	$	248,185	$	148,934	$	85,018	$	145,231
Long-term debt, net of debt issuance costs (1)		758,911		617,387		617,744		711,808		794,652
Other long-term liabilities		138,345		174,790		25,474		16,972		17,221
Stockholders’ equity		1,083,318		1,212,098		598,554		571,543		549,416
Total liabilities and stockholders’ equity	$	2,156,052	$	2,252,460	$	1,390,706	$	1,385,341	$	1,506,520

(1) We adopted ASU 2015-03 and ASU 2015-15 effective January 1, 2016, which required that debt issuance costs related to a recognized debt liability be presented in the balance sheet as a direct reduction from the carrying amount of that debt liability and as a result, $8.7 million of debt issuance costs related to our long-term debt were reclassified from deferred financing costs and other noncurrent assets to long-term debt in our consolidated balance sheet as of December 31, 2015.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations.

Introduction

The following discussion and analysis should be read in conjunction with the “Selected Historical Financial Information” and the accompanying consolidated financial statements and related notes included elsewhere in this Annual Report on Form 10-K. This section and other parts of this Annual Report on Form 10-K contain forward-looking statements that involve risks and uncertainties. See the “Cautionary Note Regarding Forward-Looking Statements” at the beginning of this Annual Report on Form 10-K. Forward-looking statements are not guarantees of future performance and our actual results may differ significantly

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from the results discussed in the forward-looking statements. Factors that might cause such differences include, but are not limited to, those discussed in “Items 1 and 2. Business and Properties - Business - Operations - Environmental Matters and Regulation;” “Items 1 and 2. Business and Properties - Business - Operations - Other Regulation of the Oil and Gas Industry;” and “Item 1A. Risk Factors” above, all of which are incorporated herein by reference. We assume no obligation to revise or update any forward-looking statements for any reason, except as required by law.

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.

Future acquisitions or dispositions could have a material impact on our financial condition and results of operations by increasing or decreasing our reserves, production and revenues as well as expenses and future capital expenditures. We currently anticipate that we would finance any future acquisitions with available borrowings under our Amended Credit Facility, sales of properties, and/or the issuance of debt, equity or equity-linked securities. Our prior acquisitions and capital expenditures were financed with a combination of cash on hand, funding from the sale of our equity securities, our Amended Credit Facility, other debt financing and cash flows from operations.

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

The following table summarizes the estimated net proved reserves and related Standardized Measure for the years indicated. The Standardized Measure is not intended to represent the current market value of our estimated oil and natural gas reserves.

	Year Ended December 31,
	2019		2018		2017
Estimated net proved reserves (MMBoe)		127.4		104.6		85.8
Standardized measure (1) (in millions)	$	973.9	$	1,276.0	$	829.3

(1) December 31, 2019 reserves were based on average prices of $55.85 WTI per Bbl of oil, $2.58 Henry Hub per Mcf of natural gas and a percentage of the of the average oil price per Bbl of NGL. December 31, 2018 reserves were based on average prices of $65.56 WTI for oil, $3.10 Henry Hub for natural gas and $32.71 for NGLs. December 31, 2017 reserves were based on average prices of $51.34 WTI for oil, $2.98 Henry Hub for natural gas and $27.40 for NGLs.

Commodity prices are inherently volatile and are influenced by many factors outside of our control. As of February 4, 2020, we have hedged 5,857,500 barrels of oil, or approximately 54% of our expected 2020 production, and 1,912,500 barrels of oil for our 2021 production at price levels that provide some economic certainty to our cash flows. 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.

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

For the year ended December 31, 2018, as a result of the closing of the Merger on March 19, 2018, Fifth Creek’s revenues and expenses are included in the Audited Consolidated Statement of Operations beginning on March 19, 2018.

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Results of Operations

Year Ended December 31, 2019 Compared with Year Ended December 31, 2018

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

	Year Ended December 31,				Increase (Decrease)
	2019		2018		Amount				Percent
	($ in thousands, except per unit data)
Operating Results:
Operating Revenues								��
Oil, gas and NGL production	$	452,274	$	452,917	$	(643	)			—	%
Other operating revenues, net		385		100		285				285	%
Total operating revenues	$	452,659	$	453,017	$	(358	)			—	%
Operating Expenses
Lease operating expense	$	37,796	$	27,850	$	9,946				36	%
Gathering, transportation and processing expense		10,685		4,644		6,041				130	%
Production tax expense		23,541		36,762		(13,221	)			(36	)%
Exploration expense		143		70		73				104	%
Impairment and abandonment expense		9,642		719		8,923				*nm
(Gain) loss on sale of properties		2,901		1,046		1,855				177	%
Depreciation, depletion and amortization		321,276		228,480		92,796				41	%
Unused commitments		17,706		18,187		(481	)			(3	)%
General and administrative expense (1)		44,759		45,130		(371	)			(1	)%
Merger transaction expense		4,492		7,991		(3,499	)			(44	)%
Other operating expenses, net		402		1,273		(871	)			(68	)%
Total operating expenses	$	473,343	$	372,152	$	101,191				27	%
Production Data:
Oil (MBbls)		7,668		6,330		1,338				21	%
Natural gas (MMcf)		16,614		12,864		3,750				29	%
NGLs (MBbls)		2,101		1,697		404				24	%
Combined volumes (MBoe)		12,538		10,171		2,367				23	%
Daily combined volumes (Boe/d)		34,351		27,866		6,485				23	%
Average Realized Prices before Hedging:
Oil (per Bbl)	$	52.86	$	62.04	$	(9.18	)			(15	)%
Natural gas (per Mcf)		1.56		1.75		(0.19	)			(11	)%
NGLs (per Bbl)		10.00		22.18		(12.18	)			(55	)%
Combined (per Boe)		36.07		44.53		(8.46	)			(19	)%
Average Realized Prices with Hedging:
Oil (per Bbl)	$	54.39	$	54.51	$	(0.12	)			—	%
Natural gas (per Mcf)		1.50		1.76		(0.26	)			(15	)%
NGLs (per Bbl)		10.00		22.18		(12.18	)			(55	)%
Combined (per Boe)		36.92		39.85		(2.93	)			(7	)%
Average Costs (per Boe):
Lease operating expense	$	3.01	$	2.74	$	0.27				10	%
Gathering, transportation and processing expense		0.85		0.46		0.39				85	%
Production tax expense		1.88		3.61		(1.73	)			(48	)%
Depreciation, depletion and amortization		25.62		22.46		3.16				14	%
General and administrative expense (1)		3.57		4.44		(0.87	)			(20	)%

* Not meaningful.

(1) Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million (or $0.69 per Boe) and $7.2 million (or $0.71 per Boe) for the years ended December 31, 2019 and 2018, respectively.

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Production Revenues and Volumes. Production revenues decreased to $452.3 million for the year ended December 31, 2019 from $452.9 million for the year ended December 31, 2018. The decrease in production revenues was due to a 19% decrease in the average realized prices per Boe before hedging, offset by a 23% increase in production volumes. The decrease in average realized prices per Boe before hedging decreased production revenues by approximately $86.0 million, while the increase in production volumes increased production revenues by approximately $85.4 million.

Total production volumes of 12.5 MMBoe for the year ended December 31, 2019 increased from 10.2 MMBoe for the year ended December 31, 2018 primarily as a result of new wells placed into production throughout 2019.

Lease Operating Expense (“LOE”). LOE increased to $3.01 per Boe for the year ended December 31, 2019 from $2.74 per Boe for the year ended December 31, 2018. The increase per Boe for the year ended December 31, 2019 compared with the year ended December 31, 2018 is primarily related to higher initial LOE related to our early development program in the Hereford field.

Gathering, Transportation and Processing (“GTP”) Expense. GTP expense increased to $0.85 per Boe for the year ended December 31, 2019 from $0.46 per Boe for the year ended December 31, 2018.

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

GTP expense for the year ended December 31, 2019 of $0.85 per Boe is primarily associated with the Hereford Field. We expect GTP expense per Boe to increase in the future as we further develop and increase our production from the Hereford Field under the existing contractual arrangement, which has a primary term through April 2027.

Production Tax Expense. Total production taxes decreased to $23.5 million for the year ended December 31, 2019 from $36.8 million for the year ended December 31, 2018. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 5.2% and 8.1% for the years ended December 31, 2019 and 2018, respectively. The decrease in the rate for the year ended December 31, 2019 was due to a decrease in our projected 2019 Colorado severance tax effective rate.

Impairment and Abandonment Expense. Impairment and abandonment expense increased to $9.6 million for the year ended December 31, 2019 from $0.7 million for the year ended December 31, 2018. Impairment and abandonment expense for the year ended December 31, 2019 included leases that have expired and certain leases that will expire subsequent to the balance sheet date that the Company does not plan to renew. Impairment and abandonment expense for the year ended December 31, 2018 included leases that have expired.

We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. Whenever we conclude the carrying value may not be recoverable, we 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

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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.

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

Depreciation, Depletion and Amortization (“DD&A”). DD&A increased to $321.3 million for the year ended December 31, 2019 compared with $228.5 million for the year ended December 31, 2018. The increase of $92.8 million was the result of a 23% increase in production and a 14% increase in the DD&A rate for the year ended December 31, 2019 compared with the year ended December 31, 2018. The increase in production accounted for a $53.2 million increase in DD&A expense while the increase in the DD&A rate accounted for a $39.6 million increase 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 year ended December 31, 2019, the relationship of capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $25.62 per Boe compared with $22.46 per Boe for the year ended December 31, 2018. The increase in the depletion rate of 14% is the result of year end 2018 reserve adjustments.

Unused Commitments. Unused commitments expense of $17.7 million and $18.2 million for the years ended December 31, 2019 and 2018, respectively, related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.

General and Administrative Expense. General and administrative expense decreased to $44.8 million for the year ended December 31, 2019 from $45.1 million for the year ended December 31, 2018. General and administrative expense on a per Boe basis decreased to $3.57 for the year ended December 31, 2019 from $4.44 for the year ended December 31, 2018.

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Included in general and administrative expense is long-term cash and equity incentive compensation of $8.6 million and $7.2 million for the years ended December 31, 2019 and 2018, respectively. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2019 and 2018 are shown in the following table:

	Year Ended December 31,
	2019		2018
	(in thousands)
Nonvested common stock	$	6,601	$	6,036
Nonvested common stock units		1,177		1,138
Nonvested performance cash units (1)		844		52
Total	$	8,622	$	7,226

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

Merger Transaction Expense. Merger transaction expense was $4.5 million and $8.0 million for the years ended December 31, 2019 and December 31, 2018, respectively. Transaction expenses 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 $58.1 million for the year ended December 31, 2019 from $52.7 million for the year ended December 31, 2018. The increase for the year ended December 31, 2019 was due to borrowings under the Amended Credit Facility. See Note 5 for additional information.

Commodity Derivative Gain (Loss). Commodity derivative loss was $99.0 million for the year ended December 31, 2019 compared with a gain of $93.3 million for the year ended December 31, 2018. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of December 31, 2019 and 2018 or during the periods then ended.

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

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

	Year Ended December 31,
	2019			2018
	(in thousands)
Realized gain (loss) on derivatives (1)	$	10,667		$	(47,587	)
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)		(81,166	)		20,940
Unrealized gain (loss) on derivatives (1)		(28,454	)		119,996
Total commodity derivative gain (loss)	$	(98,953	)	$	93,349

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

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In 2019, approximately 88% of our oil volumes and 19% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $11.7 million and a decrease in natural gas income of $1.0 million after settlements. In 2018, approximately 73% of our oil volumes and 14% of our natural gas volumes were covered by financial hedges, which resulted in a decrease in oil revenues of $47.7 million and an increase natural gas revenues of $0.1 million after settlements.

Income Tax (Expense) Benefit. For the year ended December 31, 2019, we continue to believe that it is more likely than not that we will be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence includes the scheduled reversal of deferred tax liabilities, assets acquired in connection with the Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence.

For the year ended December 31, 2018, we determined that it was more likely than not that we would be able to realize a portion of our deferred tax assets. This determination was made by considering all available evidence in assessing the need for a valuation allowance. Such evidence included the scheduled reversal of deferred tax liabilities, assets acquired in connection with the Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies. In making this assessment, judgment is required in considering the relative weight of negative and positive evidence. As a result of the analysis conducted, we reversed the majority of the valuation allowance on certain deferred tax assets and recorded income tax expense of $1.8 million for the year ended December 31, 2018.

Year Ended December 31, 2018 Compared with Year Ended December 31, 2017

A discussion of our results of operations for the year ended December 31, 2018 compared with December 31, 2017 can be found in the “Management’s Discussion and Analysis of Financial Condition and Results of Operations” section of our Annual Report on Form 10-K for the year ended December 31, 2018.

Capital Resources and Liquidity

Our primary sources of liquidity since our formation have been net cash provided by operating activities, sales and other issuances of equity and debt securities, bank credit facilities, proceeds from sale-leasebacks, joint exploration agreements and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity. Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. We believe that we have sufficient liquidity available to us from cash on hand, cash flows from operations and under our Amended Credit Facility for our planned uses of capital over the next twelve months.

The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million, and an initial borrowing base of $500.0 million. On October 1, 2019, the commitment and borrowing base amounts were reaffirmed at $500.0 million. At December 31, 2019, we had cash and cash equivalents of $16.4 million and a $140.0 million balance outstanding under our Amended Credit Facility. At December 31, 2018, we had cash and cash equivalents of $32.8 million and no amounts outstanding under our Amended Credit Facility. Our effective borrowing capacity as of December 31, 2019 was reduced by $26.0 million to $334.0 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.

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On March 19, 2018, we completed the Merger with Fifth Creek. The Merger was effected through the issuance of 2 million shares of our common stock (100 million shares on a pre-split basis, see Note 16 to the Consolidated Financial Statements), with a fair value of $484.0 million on the date of closing, and the repayment of $53.9 million of Fifth Creek debt. See “Items 1. and 2. Business and Properties - Business - Significant Business Developments - Merger with Fifth Creek Energy Operating Company, LLC” for additional information.

Cash Flow from Operating Activities

Net cash provided by operating activities was $278.6 million, $231.4 million and $122.0 million in 2019, 2018 and 2017, respectively. The changes in net cash provided by operating activities are discussed above in “Results of Operations”. The increase in cash provided by operating activities from 2017 to 2019 was primarily due to an increase in production revenues.

Commodity Hedging Activities

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

To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap contracts to receive fixed prices for a portion of our production. At December 31, 2019, we had in place crude oil swaps covering portions of our 2020 and 2021 production.

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

All derivative instruments, other than those that meet the normal purchase and normal sales exception as mentioned above, are recorded at fair market value and are included in the Consolidated Balance Sheets as assets or liabilities. All fair values are adjusted for non-performance risk. All changes in the derivative’s fair value are recorded in earnings. These mark-to-market adjustments produce a degree of earnings volatility but have no cash flow impact relative to changes in market prices. Our cash flow is only impacted when the associated derivative instrument contract is settled by making a payment to or receiving a payment from the counterparty.

The following table includes all hedges entered into through February 4, 2020.

Contract	Total Hedged Volumes		Quantity Type	Weighted Average Fixed Price		Index Price (1)
Swap Contracts:
2020
Oil		5,857,500	Bbls	$	58.32	WTI
2021
Oil		1,912,500	Bbls	$	54.50	WTI

(1) WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange.

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By removing the price volatility from a portion of our oil 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:

	Year Ended December 31,
Basin/Area	2019		2018		2017
	(in millions)
DJ	$	355.0	$	508.2	$	251.5
Other		6.0		0.7		9.2
Total (1)(2)	$	361.0	$	508.9	$	260.7

	Year Ended December 31,
	2019		2018		2017
	(in millions)
Acquisitions of proved and unproved properties and other real estate	$	4.7	$	19.9	$	20.4
Drilling, development, exploration and exploitation of oil and natural gas properties		319.3		448.9		226.9
Gathering and compression facilities		20.4		37.1		11.9
Geologic and geophysical costs		12.0		2.3		0.5
Furniture, fixtures and equipment		4.6		0.7		1.0
Total (1)(2)	$	361.0	$	508.9	$	260.7

(1) Includes exploration and abandonement expense, which are expensed under successful efforts accounting, of $5.9 million, $0.8 million and $0.5 million for the years ended December 31, 2019, 2018 and 2017, respectively.

(2) Excludes $716.2 million related to the proved and unproved oil and gas properties and furniture, equipment and other assets acquired in the Merger for the year ended December 31, 2018.

Capital expenditures for acquisitions of proved and unproved properties and other real estate were $4.7 million for the year ended December 31, 2019. This was primarily related to acquisitions of proved and unproved properties in the DJ Basin. The decrease in drilling, development, exploration and exploitation of oil and natural gas properties to $319.3 million for the year ended December 31, 2019 from $448.9 million for the year ended December 31, 2018 was primarily related to a decrease in development drilling and completion activities within the DJ Basin. The increase in geologic and geophysical costs to $12.0 million for the year ended December 31, 2019 from $2.3 million for the year ended December 31, 2018 is related to activity in the Hereford field.

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Capital expenditures for acquisitions of proved and unproved properties and other real estate were $19.9 million for the year ended December 31, 2018. This was primarily related to acquisitions of proved and unproved properties in the DJ Basin. The increase in drilling, development, exploration and exploitation of oil and natural gas properties to $448.9 million from $226.9 million for the year ended December 31, 2017 primarily related to an increase in development drilling and completion activities within the DJ Basin, including drilling and completion activities associated with properties acquired in the Merger. Capital expenditures for the year ended December 31, 2018 exclude any amounts associated with the purchase price of the Merger.

Our current estimated capital expenditure budget for 2020 is $200.0 million to $220.0 million. The budget includes facilities costs and excludes acquisitions. We may adjust capital expenditures as business conditions and operating results warrant. The amount, timing and allocation of capital expenditures is generally discretionary and within our control. If oil, natural gas and NGL prices decline to below acceptable levels or costs increase above acceptable levels, we could choose to defer a portion of our budgeted capital expenditures until later periods to achieve the desired balance between sources and uses of liquidity. We would generally do this by prioritizing capital projects to first focus on those that we believe will have the highest expected financial returns and ability to generate near-term cash flow.

We believe that we have sufficient available liquidity with available cash on hand, cash under the Amended Credit Facility and cash flow from operations to fund our 2020 budgeted capital expenditures. Future cash flows are subject to a number of variables, including our level of oil and natural gas production, commodity prices and operating costs. There can be no assurance that operations and other capital resources will provide sufficient amounts of cash flow to maintain planned levels of capital expenditures.

Financing Activities

Merger Financing. On March 19, 2018, we completed the Merger with Fifth Creek. The Merger was effected through the issuance of 2 million shares of our common stock (100 million shares on a pre-split basis, see Note 16 to the Consolidated Financial Statements), with a fair value of $484.0 million, and the repayment of $53.9 million of Fifth Creek debt.

Amended Credit Facility. We had $140.0 million and zero outstanding borrowings under the Amended Credit Facility as of December 31, 2019 and 2018, respectively. The Amended Credit Facility provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing base of $500.0 million. On October 1, 2019, the commitment and borrowing base amounts were reaffirmed at $500.0 million. 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 the Company has more than $100 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 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.

Borrowing bases are computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by our lenders, as well as any other outstanding debt. Lower commodity prices will generally result in a lower borrowing base.

We are in compliance with all financial covenants as of December 31, 2019 and have complied with all financial covenants since issuance. We expect to be in compliance with all financial covenants based on the 2020 budget at current commodity prices.

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Our outstanding debt is summarized below:

		As of December 31, 2019							As of December 31, 2018
	Maturity Date	Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
		(in thousands)
Amended Credit Facility	September 14, 2023	$	140,000	$	—		$	140,000	$	—	$	—		$	—
7.0% Senior Notes	October 15, 2022		350,000		(2,372	)		347,628		350,000		(3,210	)		346,790
8.75% Senior Notes	June 15, 2025		275,000		(3,717	)		271,283		275,000		(4,403	)		270,597
Lease Financing Obligation	August 10, 2020		—		—			—		1,859		—			1,859
Total Debt		$	765,000	$	(6,089	)	$	758,911	$	626,859	$	(7,613	)	$	619,246
Less: Current Portion of Long-Term Debt (1)			—		—			—		1,859		—			1,859
Total Long-Term Debt (2)		$	765,000	$	(6,089	)	$	758,911	$	625,000	$	(7,613	)	$	617,387

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

(2) See Note 5 for additional information.

Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s 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 provisions that are linked to our credit ratings, nor do we have any credit rating triggers that would accelerate the maturity of amounts due under our Amended Credit Facility, the 7.0% Senior Notes or the 8.75% Senior Notes. However, our ability to raise funds and the costs of any financing activities will 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 and subsequent to December 31, 2019 is provided in the following table:

	Payments Due By Year
	Year 1		Year 2		Year 3		Year 4		Year 5		Thereafter		Total
	(in thousands)
Notes payable (1)	$	41	$	—	$	—	$	140,000	$	—	$	—	$	140,041
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)		23,134		19,778		13,064		14,600		14,640		4,800		90,016
Gas gathering and processing agreements (5)(6)		4,569		1,997		—		—		—		—		6,566
Asset retirement obligations (7)		2,218		2,028		2,000		2,020		2,197		15,246		25,709
Derivative liability (8)		4,411		671		—		—		—		—		5,082
Operating leases (9)		2,056		2,355		2,044		2,024		2,078		7,577		18,134
Other (10)		3,448		805		805		745		—		—		5,803
Total	$	88,440	$	76,197	$	416,476	$	183,452	$	42,978	$	314,651	$	1,122,194

(1) Included in notes payable is the outstanding principal amount under our Amended Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Amended Credit Facility because the Amended Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. Also included in notes payable is interest on a $26.0 million letter of credit that accrues at 1.75% and 0.125% per annum for participation fees and fronting fees, respectively. The expected term for the letter of credit is January 31, 2020.

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(2) The aggregate principal amount of our 7.0% Senior Notes is $350.0 million. We are obligated to make semi-annual interest payments through maturity on October 15, 2022 equal to $12.3 million. See Note 5 to the accompanying financial statements for additional information.

(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. See Note 5 to the accompanying financial statements for additional information.

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

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

(6) Includes reimbursement obligations of $2.4 million. The reimbursement obligations require us to pay a monthly gathering and processing fee per Mcf of production to reimburse midstream entities for costs to construct gas gathering and processing facilities. If the costs are not reimbursed by us via the monthly gathering and processing fees, we must pay the difference.

(7) Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.

(8) Derivative liability represents the net fair value for oil commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2019. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates” in Part II, Item 7 and in “Commodity Hedging Activities” above for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.

(9) 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.

(10) 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 December 31, 2019.

Trends and Uncertainties

Regulatory Trends

Our future Rockies operations and cost of doing business may be affected by changes in regulations and the ability to obtain drilling permits. The regulatory environment continues to become more restrictive, which limits our ability to, and increases the costs of, conducting our operations. Areas in which we operate are subject to federal, state and local regulations. Additional and more restrictive regulations have been seen at each of these governmental levels recently and there are initiatives underway to implement additional regulations and prohibitions on oil and gas activities. New rules may further impact our ability to obtain drilling permits and other required approvals in a timely manner and increase the costs of such permits or approvals. This may create substantial uncertainty about our production and capital expenditure targets. Efforts related to climate change organized around a “keep it in the ground” message have gained traction in New York and other coastal states, as well as internationally, notably in France and Germany. See “Business and Properties-Operations-Environmental Matters and Regulation” for a summary of certain environmental regulations that affect our business and related developments, including potential future regulatory developments.    

Declining Commodity Prices. The severe decline in oil prices that occurred in 2014 and 2015 increased the volatility and amplitude of the other risks facing us as described in this report and had an impact on our business and financial condition. The significant decrease in oil prices in late 2018 and 2019 had a similar effect. If oil prices decrease from current levels, our planned drilling 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.

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The sustained decline in commodity prices may also expose us to unexpected liability for plugging and abandoning wells, and associated reclamation, including for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contract obligations to us as provided for in purchase and sale agreements, regulatory agencies and landowners may demand that we perform such activities. Recent case law in Wyoming has increased such exposure for companies that have divested assets to no longer viable entities, and we have received demands from the Bureau of Land Management and a several large ranches to plug and abandon wells, and conduct associated reclamation, on properties we no longer own. We recognized $0.3 million and $1.9 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the years ended December 31, 2019 and 2018, respectively.

Critical Accounting Policies and Estimates

The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with accounting principles generally accepted in the United States. The preparation of these financial statements requires us to make estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses and related disclosure of contingent assets and liabilities. Certain accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. We evaluate our estimates and assumptions on a regular basis. We base our estimates on historical experience and various other assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying values of assets and liabilities that are not readily apparent from other sources. Actual results may differ from these estimates and assumptions used in preparation of our consolidated financial statements. We provide expanded discussion of our more significant accounting policies, estimates and judgments below. We believe these accounting policies reflect our more significant estimates and assumptions used in preparation of our consolidated financial statements. See Note 2 of the Notes to the Consolidated Financial Statements for a discussion of additional accounting policies and estimates made by management.

Oil and Gas Properties

Our oil, natural gas and NGL exploration and production activities are accounted for using the successful efforts method. Under this method, all property acquisition costs and costs of exploratory and development wells are capitalized when incurred, pending determination of whether the well has found proved reserves. If an exploratory well does not find proved reserves, the costs of drilling the well are charged to expense and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. If an exploratory well does find proved reserves, the costs remain capitalized, are included within additions to oil and gas properties and remain within cash flows from investing activities in the Consolidated Statements of Cash Flows. The costs of development wells are capitalized whether proved reserves are added or not. All exploratory wells are evaluated for economic viability within one year of well completion, and the related capitalized costs are reviewed quarterly. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well, and we are making sufficient progress assessing the reserves and the economic and operating viability of the project. Oil and gas lease acquisition costs are also capitalized. Upon sale or retirement of depreciable or depletable property, the cost and related accumulated DD&A are eliminated from the accounts and the resulting gain or loss is recognized. Interest cost is capitalized as a component of property cost for significant exploration and development projects that require greater than six months to be readied for their intended use.

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The application of the successful efforts method of accounting requires managerial judgment to determine the proper classification of wells designated as developmental or exploratory, which will ultimately determine the proper accounting treatment of the costs incurred. In addition to development on exploratory wells, we may drill scientific wells that are only used for data gathering purposes. The costs associated with these scientific wells are expensed as incurred as exploration expense. The results from a drilling operation can take considerable time to analyze, and the determination that commercial reserves have been discovered requires both judgment and industry experience.

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

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

We review our oil and natural gas properties for impairment on a quarterly basis or whenever events and circumstances indicate that a decline in the recoverability of their carrying value may have occurred. 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.

Oil and gas properties are assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, we utilize the income valuation technique, which involves calculating the present value of future net cash flows, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell. The estimated fair value of assets held for sale may be materially different from sales proceeds that we eventually realize due to a number of factors including but not limited to the differences in expected future commodity pricing, location and quality differentials, our relative desire to dispose of such properties based on facts and circumstances impacting our business at the time we agree to sell, such as our position in the field subsequent to the sale and plans for future acquisitions or development in core areas.

Our investment in producing oil and natural gas properties includes an estimate of the future costs associated with dismantlement, abandonment and restoration of our properties. The present value of the estimated future costs to dismantle, abandon and restore a well location are added to the capitalized costs of our oil and gas properties and recorded as a long-term liability. The capitalized cost is included in the oil and natural gas property costs that are depleted over the life of the assets.

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The provision for depletion of oil and gas properties is calculated on a field-by-field basis using the units-of-production method. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Our rate of recording DD&A is dependent upon our estimates of total proved and proved developed reserves, which incorporate assumptions regarding future development and abandonment costs as well as our level of capital spending. If the estimates of total proved or proved developed reserves decline, the rate at which we record DD&A expense increases, reducing our net income. This decline may result from lower market prices, which may make it uneconomic to drill for and produce higher cost fields. We are unable to predict changes in reserve quantity estimates as such quantities are dependent on the success of our exploitation and development program, as well as future economic conditions.

Oil and Gas Reserve Quantities

Our estimate of proved reserves is based on the quantities of oil and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions. Our proved reserves estimates are audited on a well-by-well basis by an independent third party engineering firm. In the aggregate, the independent third party petroleum engineer estimates of total net proved reserves are within 10% of our internal estimates as of December 31, 2019.

Reserves and their relation to estimated future net cash flows impact our depletion and impairment calculations. As a result, adjustments to depletion and impairment are made concurrently with changes to reserves estimates. We prepare our reserves estimates, and the projected cash flows derived from these reserves estimates, in accordance with SEC guidelines. Our independent third party engineering firm adheres to the same guidelines when auditing our reserve reports. The accuracy of our reserves estimates is a function of many factors including the following: the quality and quantity of available data, the interpretation of that data, the accuracy of various mandated economic assumptions and the judgments of the individuals preparing the reserves estimates.

The process of estimating oil and natural gas reserves is very complex, requiring significant decisions in the evaluation of all available geological, geophysical, engineering and economic data. The data for a given field may also change substantially over time as a result of numerous factors, including additional development activity, evolving production history and continued reassessment of the viability of production under varying economic conditions. As a result, material revisions to existing reserves estimates may occur from time to time. Although every reasonable effort is made to ensure that the reported reserves estimates represent the most accurate assessments possible, the subjective decisions and variances in available data for various fields make these estimates generally less precise than other estimates included in our financial statements. As such, reserves estimates may materially vary from the ultimate quantities of oil and natural gas eventually recovered.

Please refer to the reserve disclosures in “Items 1 and 2 - Business and Properties” for further detail on reserves data.

Revenue Recognition

All of our sales of oil, gas and NGLs are made under contracts with customers, whereby revenues are recognized when we satisfy our performance obligations and the customer obtains control of the product. Performance obligations under our 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, we do not have any unsatisfied performance obligations. Our 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 our contracts with customers do not require us to constrain variable consideration for accounting purposes. Our contracts with customers typically require payment within one month of delivery.

Under our 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 us for the value of the residue gas and NGLs at current market prices for each product. Our 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 our oil,

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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 the 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 Consolidated Statements of Operations.

Gas imbalances from the sale of natural gas are recorded on the basis of gas actually sold by us. If our 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.

Income Taxes and Uncertain Tax Positions

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 are also recognized for net operating loss carry forwards and tax credits that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates to the differences between financial statement and income tax reporting. We routinely assess the realizability of our deferred tax assets. If we conclude that it is more likely than not that some portion or all of the deferred tax assets will not be realized under accounting standards, the tax asset would be reduced by a valuation allowance. We consider estimated future taxable income in making such assessments, including the future reversal of taxable temporary differences. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). There can be no assurance that facts and circumstances will not materially change and require us to adjust deferred tax asset valuation allowances in the future.

Accounting guidance for recognizing and measuring uncertain tax positions prescribes a more likely than not recognition threshold that a tax position must meet for any of the benefit of the uncertain tax position to be recognized in the financial statements. Guidance is also provided regarding de-recognition, classification and disclosure of these uncertain tax positions. Based on this guidance, we regularly analyze tax positions taken or expected to be taken in a tax return based on the threshold prescribed. Tax positions that do not meet or exceed this threshold are considered uncertain tax positions. Penalties, if any, related to uncertain tax positions would be recorded in other expenses. We currently do not have any uncertain tax positions recorded as of December 31, 2019.

We are subject to taxation in many jurisdictions, and the calculation of our tax liabilities involves dealing with uncertainties in the application of complex tax laws and regulations in various taxing jurisdictions. If we ultimately determine that the payment of these liabilities will be unnecessary, we reverse the liability and recognize a tax benefit during the period in which we determine the liability no longer applies. Conversely, we record additional tax charges in a period in which we determine that a recorded tax liability is less than we expect the ultimate assessment to be. See “Results of Operations- Income Tax (Expense) Benefit” above for a discussion of changes to the valuation allowance during 2018.

New Accounting Pronouncements

For further information on the effects of recently adopted accounting pronouncements and the potential effects of new accounting pronouncements, refer to the Summary of Significant Accounting Policies (in Note 2) of the Notes to Consolidated Financial Statements.

Item 7A. 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

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oil, natural gas and NGL prices and interest rates. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. This forward-looking information provides indicators of how we view and manage our ongoing market risk exposures. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.

Commodity Price Risk

Our primary market risk exposure is to the prices we receive for our production. Commodity pricing is primarily driven by the prevailing worldwide price for crude oil and spot regional market prices applicable to our U.S. natural gas production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue in the future. The prices we receive for future production depend on many factors outside of our control, including volatility in the differences between product prices at sales points and the applicable index price. Based on our average daily production and our derivative contracts in place for the year ended December 31, 2019, our income before taxes would have decreased by approximately $1.6 million for each $5.00 per barrel decrease in crude oil prices, $1.3 million for each $0.10 decrease per MMBtu in natural gas prices and $1.9 million for each $1.00 per barrel decrease in NGL prices.

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

As of February 4, 2020, we have swap contracts related to oil volumes in place for the following periods indicated. Further detail of these hedges is summarized in the table presented under “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations— Capital Resources and Liquidity— Commodity Hedging Activities”.

	For the Year 2020				For the Year 2021
	Derivative Volumes		Weighted Average Price		Derivative Volumes		Weighted Average Price
Oil (Bbls)		5,857,500	$	58.32		1,912,500	$	54.50

Item 8. Financial Statements and Supplementary Data.

The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

Evaluation of Disclosure Controls and Procedures. As of December 31, 2019, we carried out an evaluation, under the supervision and with the participation of management, including our principal executive officer and principal 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 Exchange Act. Based upon that evaluation, our principal executive officer and principal financial officer concluded that our disclosure controls and procedures are effective as of December 31, 2019.

Management’s Report on Internal Control Over Financial Reporting. Our management is responsible for establishing and maintaining internal control over financial reporting. Our internal control over financial reporting is a process designed under the supervision of our principal executive officer and principal financial officer to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles.

57

Management has assessed the effectiveness of our internal control over financial reporting. In making this assessment, it used the criteria set forth by the Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on our assessment we have concluded that, as of December 31, 2019, our internal control over financial reporting is effective.

Our independent registered public accounting firm has issued an attestation report on our internal control over financial reporting. That report is set forth below.

Changes in Internal Controls. There was no change in our internal control over financial reporting during the fourth fiscal quarter of 2019 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

58

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

HighPoint Resources Corporation

Denver, Colorado

Opinion on Internal Control over Financial Reporting

We have audited the internal control over financial reporting of HighPoint Resources Corporation and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2019, of the Company and our report dated February 26, 2020, expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 26, 2020

59

Item 9B. Other Information.

None.

PART III

Item 10. Directors, Executive Officers and Corporate Governance.

The information required by this item will be included in an amendment to this Form 10-K or in the “Directors and Executive Officers” section, the “Section 16(a) Beneficial Ownership Reporting Compliance” section, the “Code of Business Conduct and Ethics” section and the “Corporate Governance” section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2019, and is incorporated by reference to this report.

Item 11. Executive Compensation.

The information required by this item will be included in an amendment to this Form 10-K or in the “Executive Compensation” section and the “Director Compensation” section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2019, and is incorporated by reference to this report.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

Information regarding beneficial ownership will be included in an amendment to this Form 10-K or in the “Beneficial Owners of Securities” section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2019, and is incorporated by reference to this report.

Equity Compensation Plan Information

The following table provides aggregate information presented as of December 31, 2019 with respect to all compensation plans under which equity securities are authorized for issuance (as adjusted for the impact of the 1-for-50 reverse stock split effected on October 30, 2020).

	(a)		(b)		(c)
Plan Category	Number of Securities to be Issued Upon Exercise of Outstanding Options, Warrants and Rights		Weighted Averaged Exercise Price of Outstanding Options, Warrants and Rights		Number of Securities Remaining Available for Future Issuance (Excluding Securities Reflected in Column (a))
Equity compensation plans approved by shareholders		—	$	—		46,345
Equity compensation plans not approved by shareholders		—		—		—
Total		—	$	—		46,345

Item 13. Certain Relationships and Related Transactions and Director Independence.

The information required by this item will be included in an amendment to this Form 10-K or in the “Approval of Related Party Transactions” section and the “Corporate Governance” section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2019, and is incorporated by reference to this report.

60

Item 14. Principal Accounting Fees and Services.

The information required by this item will be included in an amendment to this Form 10-K or in the “Fees to Independent Auditors” section of the proxy statement for the 2020 annual meeting of stockholders, in either case, to be filed within 120 days after December 31, 2019, and is incorporated by reference to this report.

61

PART IV

Item 15. Exhibits, Financial Statement Schedules.

(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules.

Report of Independent Registered Public Accounting Firm	68
Consolidated Balance Sheets as of December 31, 2019 and 2018	69
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	70
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	71
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2019, 2018 and 2017	72
Notes to Consolidated Financial Statements	73

All schedules are omitted because the required information is not applicable or is not present in amounts sufficient to require submission of the schedule or because the information required is included in the Consolidated Financial Statements and Notes thereto.

62

(a)(3) Exhibits.

Exhibit Number	Description of Exhibits
2.1	Merger Agreement, dated December  4, 2017, by and among Fifth Creek Energy Operating Company, LLC, Bill Barrett Corporation, Red Rider Holdco, Inc., Rio Merger Sub, LLC, Rider Merger Sub, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 2.1 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on December 5, 2017.]
3.1	Amended and Restated Certificate of Incorporation of HighPoint Resources Corporation. [Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
3.2	HighPoint Resources Corporation Amended and Restated Bylaws. [Incorporated by reference to Exhibit 3.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.1.1*	Description of Capital Stock.
4.1.2	Specimen Certificate of Common Stock. [Incorporated by reference to Exhibit 4.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
4.2	Base Indenture, dated July  8, 2009, between Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on July 8, 2009.]
4.2.1	Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March  12, 2012, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on March 12, 2012.]
4.2.2	Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated December  13, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on December 15, 2017.]
4.2.3	Second Supplemental Indenture to Fourth Supplemental Indenture for 7% Senior Notes due 2022, dated March  19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
4.3	Indenture for 8.75% Senior Notes due 2025, dated April  28, 2017, among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.1 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on April 28, 2017.]
4.3.1	First Supplemental Indenture for 8.75% Senior Notes due 2025, dated December  13, 2017, by and among Bill Barrett Corporation, certain subsidiary guarantors, and Deutsche Bank Trust Company. [Incorporated by reference to Exhibit 4.2 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on December 15, 2017.]
4.3.2	Second Supplemental Indenture for 8.75% Senior Notes due 2025, dated March  19, 2018, among Bill Barrett Corporation, the Company, and Deutsche Bank Trust Company Americas, as Trustee. [Incorporated by reference to Exhibit 4.2 of our Current Report on Form 8-K filed with the Commission on March 19, 2018.]
10.1	Fourth Amended and Restated Credit Agreement, dated as of September  14, 2018, among HighPoint Resources Corporation as guarantor and its wholly owned subsidiary and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on September 17, 2018.]

63

Exhibit Number	Description of Exhibits
10.2+	Form of Indemnification Agreement, between HighPoint Resources Corporation and each of the directors and certain executive officers of the Company. [Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
10.3(a)+	2012 Equity Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation’s Definitive Proxy Statement filed with the Commission on April 6, 2017.]
10.3(b)+	Amendment to the 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.5(b) of our Annual Report on Form 10-K filed with the Commission on February 26, 2019.]
10.4+	Form of Restricted Common Stock Unit Award for 2012 Equity Incentive Plan. [Incorporated by reference to Exhibit 10.2 to Bill Barrett Corporation’s Current Report on Form 8-K filed with the Commission on July 2, 2012.]
10.5+	Cash Incentive Plan. [Incorporated by reference to Appendix A to Bill Barrett Corporation’s Definitive Proxy Statement for the 2016 Annual Meeting of Stockholders filed with the Commission on April 7, 2016.]
10.6+	Form of Change in Control Severance Protection Agreement. [Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the Commission on May 8, 2018.]
10.7*	Form of Stockholders Agreement between Red Rider Holdco, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P.
10.8	Waiver to Stockholders Agreement, dated as of December  4, 2018, by and among HighPoint Resources Corporation, Fifth Creek Energy Company, LLC and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on December 6, 2018.]
10.8+	Deferred Compensation Plan. [Incorporated by reference to Exhibit 10.1 to Bill Barrett Corporation’s Quarterly Report on Form 10-Q filed with the Commission on May 5, 2016.]
21.1*	Subsidiaries of the Registrant.
23.1*	Consent of Deloitte & Touche LLP.
23.2*	Consent of Netherland, Sewell & Associates, Inc., Independent Petroleum Engineers.
31.1*	Rule 13a-14(a)/15d-14(a) Certification of Chief Executive Officer.
31.2*	Rule 13a-14(a)/15d-14(a) Certification of Chief Financial Officer.
32**	Section 1350 Certification of Chief Executive Officer and Chief Financial Officer.
99.1*	Report of Netherland, Sewell & Associates, Inc. dated January  21, 2020, concerning audit of oil and gas reserve estimates.
101.INS	XBRL Instance Document (The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.)
101.SCH	XBRL Taxonomy Extension Schema Document

64

Exhibit Number	Description of Exhibits
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document
101.LAB	XBRL Taxonomy Extension Label Linkbase Document
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document
104	Cover Page Interactive Data File (embedded within the Inline XBRL document).

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

65

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	February 26, 2020	By:	/s/ R. Scot Woodall
			R. Scot Woodall
			Chief Executive Officer and President

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ R. Scot Woodall	Chief Executive Officer, President and Director (Principal Executive Officer)	February 26, 2020
R. Scot Woodall
/s/ William M. Crawford	Chief Financial Officer (Principal Financial Officer)	February 26, 2020
William M. Crawford
/s/ David R. Macosko	Senior Vice President— Accounting (Principal Accounting Officer)	February 26, 2020
David R. Macosko
/s/ Jim W. Mogg	Director	February 26, 2020
Jim W. Mogg
/s/ Mark S. Berg	Director	February 26, 2020
Mark S. Berg
/s/ Scott A. Gieselman	Director	February 26, 2020
Scott A. Gieselman
/s/ Craig S. Glick	Director	February 26, 2020
Craig S. Glick
/s/ Andrew C. Kidd	Director	February 26, 2020
Andrew C. Kidd
/s/ Lori A. Lancaster	Director	February 26, 2020
Lori A. Lancaster
/s/ William F. Owens	Director	February 26, 2020
William F. Owens
/s/ Edmund P. Segner, III	Director	February 26, 2020
Edmund P. Segner, III
/s/ Michael R. Starzer	Director	February 26, 2020
Michael R. Starzer
/s/ Randy I. Stein	Director	February 26, 2020
Randy I. Stein
/s/ Michael E. Wiley	Director	February 26, 2020
Michael E. Wiley

66

FINANCIAL STATEMENTS

INDEX TO FINANCIAL STATEMENTS

HighPoint Resources Corporation
Report of Independent Registered Public Accounting Firm	68
Consolidated Balance Sheets as of December 31, 2019 and 2018	69
Consolidated Statements of Operations for the years ended December 31, 2019, 2018 and 2017	70
Consolidated Statements of Cash Flows for the years ended December 31, 2019, 2018 and 2017	71
Consolidated Statements of Stockholders’ Equity for the years ended December 31, 2019, 2018 and 2017	72
Notes to Consolidated Financial Statements	73

67

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the shareholders and Board of Directors of

HighPoint Resources Corporation

Denver, Colorado

Opinion on the Financial Statements

We have audited the accompanying consolidated balance sheets of HighPoint Resources Corporation and subsidiaries (the Company) (formerly Bill Barrett Corporation) as of December 31, 2019 and 2018, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2019, based on the criteria established in the Internal Control—Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 26, 2020, expressed an unqualified opinion on the Company’s internal control over financial reporting.

Basis for Opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.

/s/ Deloitte & Touche LLP

Denver, Colorado

February 26, 2020 (December 16, 2020 as to the effects of the reverse stock split described in Note 16)

We have served as the Company’s auditor since 2003.

68

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED BALANCE SHEETS

	As of December 31,
	2019			2018
	(in thousands, except share data)
Assets:
Current assets:
Cash and cash equivalents	$	16,449		$	32,774
Accounts receivable, net of allowance for doubtful accounts		62,120			72,943
Derivative assets		3,916			81,166
Prepayments and other current assets		3,952			2,898
Total current assets		86,437			189,781
Property and equipment — at cost, successful efforts method for oil and gas properties:
Proved oil and gas properties		2,644,129			2,195,310
Unproved oil and gas properties, excluded from amortization		357,793			468,208
Furniture, equipment and other		29,804			20,662
		3,031,726			2,684,180
Accumulated depreciation, depletion, amortization and impairment		(967,552	)		(654,657	)
Total property and equipment, net		2,064,174			2,029,523
Derivative assets		—			27,289
Other noncurrent assets		5,441			5,867
Total	$	2,156,052		$	2,252,460
Liabilities and Stockholders’ Equity:
Current liabilities:
Accounts payable and accrued liabilities	$	71,638		$	131,379
Amounts payable to oil and gas property owners		37,922			55,792
Production taxes payable		61,507			59,155
Derivative liabilities		4,411			—
Current portion of long-term debt		—			1,859
Total current liabilities		175,478			248,185
Long-term debt, net of debt issuance costs		758,911			617,387
Asset retirement obligations		23,491			27,330
Deferred income taxes		97,418			139,534
Other noncurrent liabilities		17,436			7,926
Commitments and contingencies (Note 14)
Stockholders’ equity:
Common stock, $0.001 par value; authorized 8,000,000 shares; 4,273,391 and 4,249,543 shares issued and outstanding at December 31, 2019 and 2018, respectively, with 59,369 and 58,243 shares subject to restrictions, respectively		4			4
Additional paid-in capital		1,777,986			1,771,936
Retained earnings (accumulated deficit)		(694,672	)		(559,842	)
Treasury stock, at cost: zero shares at December 31, 2019 and 2018		—			—
Total stockholders’ equity		1,083,318			1,212,098
Total	$	2,156,052		$	2,252,460

See notes to Consolidated Financial Statements.

69

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF OPERATIONS

	Year Ended December 31,
	2019			2018			2017
	(in thousands, except share and per share data)
Operating Revenues
Oil, gas and NGL production	$	452,274		$	452,917		$	251,215
Other operating revenues, net		385			100			1,624
Total operating revenues		452,659			453,017			252,839
Operating Expenses
Lease operating expense		37,796			27,850			24,223
Gathering, transportation and processing expense		10,685			4,644			2,615
Production tax expense		23,541			36,762			14,476
Exploration expense		143			70			83
Impairment and abandonment expense		9,642			719			49,553
(Gain) loss on sale of properties		2,901			1,046			(92	)
Depreciation, depletion and amortization		321,276			228,480			159,964
Unused commitments		17,706			18,187			18,231
General and administrative expense		44,759			45,130			42,476
Merger transaction expense		4,492			7,991			8,749
Other operating expenses, net		402			1,273			(1,514	)
Total operating expenses		473,343			372,152			318,764
Operating Income (Loss)		(20,684	)		80,865			(65,925	)
Other Income and Expense:
Interest and other income		791			1,793			1,359
Interest expense		(58,100	)		(52,703	)		(57,710	)
Commodity derivative gain (loss)		(98,953	)		93,349			(9,112	)
Gain (loss) on extinguishment of debt		—			(257	)		(8,239	)
Total other income (expense)		(156,262	)		42,182			(73,702	)
Income (Loss) before Income Taxes		(176,946	)		123,047			(139,627	)
(Provision for) Benefit from Income Taxes		42,116			(1,827	)		1,402
Net Income (Loss)	$	(134,830	)	$	121,220		$	(138,225	)
Net Income (Loss) Per Common Share, Basic	$	(32.04	)	$	32.19		$	(89.92	)
Net Income (Loss) Per Common Share, Diluted	$	(32.04	)	$	32.03		$	(89.92	)
Weighted Average Common Shares Outstanding, Basic		4,207,833			3,765,981			1,537,176
Weighted Average Common Shares Outstanding, Diluted		4,207,833			3,784,821			1,537,176

See notes to Consolidated Financial Statements.

70

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF CASH FLOWS

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Operating Activities:
Net Income (Loss)	$	(134,830	)	$	121,220		$	(138,225	)
Adjustments to reconcile to net cash provided by operations:
Depreciation, depletion and amortization		321,276			228,480			159,964
Deferred income taxes		(42,116	)		1,827			—
Impairment and abandonment expense		9,642			719			49,553
Commodity derivative (gain) loss		98,953			(93,349	)		9,112
Settlements of commodity derivatives		10,667			(47,587	)		19,099
Stock compensation and other non-cash charges		11,306			8,337			6,596
Amortization of deferred financing costs		2,556			2,365			2,194
(Gain) loss on extinguishment of debt		—			257			8,239
(Gain) loss on sale of properties		2,901			1,046			(92	)
Change in operating assets and liabilities:
Accounts receivable		10,795			(13,697	)		(18,578	)
Prepayments and other assets		(27	)		(793	)		(1,848	)
Accounts payable, accrued and other liabilities		3,030			(40,324	)		11,690
Amounts payable to oil and gas property owners		(17,870	)		34,499			10,402
Production taxes payable		2,352			28,441			3,884
Net cash provided by (used in) operating activities		278,635			231,441			121,990
Investing Activities:
Additions to oil and gas properties, including acquisitions		(426,416	)		(453,616	)		(239,631	)
Additions of furniture, equipment and other		(4,662	)		(853	)		(926	)
Repayment of debt associated with merger, net of cash acquired		—			(53,357	)		—
Proceeds from sale of properties		1,334			(221	)		101,845
Other investing activities		(1,612	)		364			(299	)
Net cash provided by (used in) investing activities		(431,356	)		(507,683	)		(139,011	)
Financing Activities:
Proceeds from debt		222,000			—			275,000
Principal and redemption premium payments on debt		(83,859	)		(469	)		(322,343	)
Proceeds from sale of common stock, net of offering costs		1			1			110,710
Other financing activities		(1,746	)		(4,982	)		(7,721	)
Net cash provided by (used in) financing activities		136,396			(5,450	)		55,646
Increase (Decrease) in Cash and Cash Equivalents		(16,325	)		(281,692	)		38,625
Beginning Cash and Cash Equivalents		32,774			314,466			275,841
Ending Cash and Cash Equivalents	$	16,449		$	32,774		$	314,466

See notes to Consolidated Financial Statements.

71

HIGHPOINT RESOURCES CORPORATION

CONSOLIDATED STATEMENTS OF STOCKHOLDERS’ EQUITY

(In thousands)

	Common Stock		Additional Paid-In Capital			Retained Earnings (Accumulated Deficit)			Treasury Stock			Total Stockholders’ Equity
Balance at December 31, 2016	$	1	$	1,113,870		$	(542,328	)	$	—		$	571,543
Cumulative effect of accounting change		—		180			(509	)		—			(329	)
Restricted stock activity and shares exchanged for tax withholding		—		1			—			(1,253	)		(1,252	)
Stock-based compensation		—		7,099			—			—			7,099
Retirement of treasury stock		—		(1,253	)		—			1,253			—
Exchange of senior notes for shares of common stock		—		48,992			—			—			48,992
Issuance of common stock, net of offering costs		1		110,725			—			—			110,726
Net income (loss)		—		—			(138,225	)		—			(138,225	)
Balance at December 31, 2017		2		1,279,614			(681,062	)		—			598,554
Restricted stock activity and shares exchanged for tax withholding		—		1			—			(1,535	)		(1,534	)
Stock-based compensation (1)		—		9,858			—			—			9,858
Retirement of treasury stock		—		(1,535	)		—			1,535			—
Issuance of common stock, merger		2		483,998			—			—			484,000
Net income (loss)		—		—			121,220			—			121,220
Balance at December 31, 2018		4		1,771,936			(559,842	)		—			1,212,098
Restricted stock activity and shares exchanged for tax withholding		—		1			—			(1,729	)		(1,728	)
Stock-based compensation		—		7,778			—			—			7,778
Retirement of treasury stock		—		(1,729	)		—			1,729			—
Net income (loss)		—		—			(134,830	)		—			(134,830	)
Balance at December 31, 2019	$	4	$	1,777,986		$	(694,672	)	$	—		$	1,083,318

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

See notes to Consolidated Financial Statements.

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HIGHPOINT RESOURCES CORPORATION

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

For the years ended December 31, 2019, 2018 and 2017

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 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.

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

Areas requiring the use of assumptions, judgments and estimates relate to volumes of oil, natural gas and NGL reserves used in calculating depreciation, depletion and amortization (“DD&A”), the amount of expected future cash flows used in determining possible impairments of oil and gas properties and the amount of future capital costs used in these calculations. Assumptions, judgments and estimates also are required in determining the fair values of assets acquired and liabilities assumed in business combinations, asset retirement obligations, the timing of dry hole costs, impairments of proved and unproved properties, valuing deferred tax assets and estimating fair values of derivative instruments and stock-based payment awards.

Accounts Receivable. Accounts receivable is comprised of the following:

	As of December 31,
	2019			2018
	(in thousands)
Accrued oil, gas and NGL sales	$	50,171		$	44,860
Due from joint interest owners		9,551			27,435
Other		2,419			754
Allowance for doubtful accounts		(21	)		(106	)
Total accounts receivable	$	62,120		$	72,943

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

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

Unproved oil and gas property costs are transferred to proved oil and gas properties if the properties are subsequently determined to be productive or are assigned proved reserves. Proceeds from sales of partial interests in unproved leases are accounted for as a recovery of cost without recognizing any gain until all costs are recovered. Unproved oil and gas properties are assessed periodically for impairment based on remaining lease terms, drilling results, reservoir performance, commodity price outlooks, future plans to develop acreage, recent sales prices of comparable properties and other relevant matters.

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

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

	As of December 31,
	2019			2018
	(in thousands)
Proved properties	$	725,964		$	663,485
Wells and related equipment and facilities		1,805,136			1,438,092
Support equipment and facilities		99,540			75,392
Materials and supplies		13,489			18,341
Total proved oil and gas properties	$	2,644,129		$	2,195,310
Unproved properties		265,387			328,409
Wells and facilities in progress		92,406			139,799
Total unproved oil and gas properties, excluded from amortization	$	357,793		$	468,208
Accumulated depreciation, depletion, amortization and impairment		(958,475	)		(642,645	)
Total oil and gas properties, net	$	2,043,447		$	2,020,873

All exploratory wells are evaluated for economic viability within one year of well completion. Exploratory wells that discover potentially economic reserves in areas where a major capital expenditure would be required before production could begin, and where the economic viability of that major capital expenditure depends upon the successful completion of further exploratory work in the area, remain capitalized if the well finds a sufficient quantity of reserves to justify its completion as a producing well and the Company is making sufficient progress assessing the reserves and the economic and operating viability of the project. As of December 31, 2019 and 2018, there were no exploratory well costs that had been capitalized for a period greater than one year since the completion of drilling. In addition, the Company had no exploratory wells as of December 31, 2019.

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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 the Company’s development plans and best estimate of future production, commodity pricing, reserve risking, gathering and transportation deductions, production tax rates, lease operating expenses and future development costs. The Company compares such undiscounted future net cash flows to the carrying amount of the oil and gas properties to determine if the carrying amount is recoverable. If the undiscounted future net cash flows exceed the carrying amount of the oil and gas properties, no impairment is taken. If the carrying amount of a property exceeds the undiscounted future net cash flows, the Company will impair the carrying value to fair value based on an analysis of quantitative and qualitative factors existing as of the balance sheet date. The Company does not believe that the undiscounted future net cash flows of its oil and gas properties represent the applicable market value. The factors used to determine fair value may include, but are not limited to, recent sales prices of comparable properties, indications from marketing activities, the present value of future revenues, net of estimated operating and development costs using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows.

Oil and gas properties are also assessed for impairment once they meet the criteria to be classified as held for sale. Assets held for sale are carried at the lower of carrying cost or fair value less costs to sell. The fair value of the assets is determined using a market approach, based on an estimated selling price, as evidenced by current marketing activities, if possible. If an estimated selling price is not available, the Company utilizes the income valuation technique which involves calculating the present value of future revenues, as discussed above. If the carrying amount of the assets exceeds the fair value less costs to sell, an impairment will result to reduce the value of the properties down to fair value less costs to sell. The estimated fair value of assets held for sale may be materially different from sales proceeds that the Company eventually realizes due to a number of factors including but not limited to the differences in expected future commodity pricing, location and quality differentials, the Company’s relative desire to dispose of such properties based on facts and circumstances impacting the Company’s business at the time the Company agrees to sell, such as the Company’s position in the field subsequent to the sale and plans for future acquisitions or development in core areas.

The Company recognized non-cash impairment and abandonment charges of $9.6 million, $0.7 million and $49.6 million for the years ended December 31, 2019, 2018 and 2017, respectively, which were included within impairment and abandonment expense in the Consolidated Statements of Operations. Impairment and abandonment expense for the year ended December 31, 2019 included leases that have expired and certain leases that will expire subsequent to the balance sheet date that the Company does not plan to renew. Impairment and abandonment expense for the year ended December 31, 2018 included leases that have expired. Impairment and abandonment expense for the year ended December 31, 2017 included a non-cash impairment charge of $37.9 million associated with the Company’s Uinta Oil Program proved properties. The properties were sold on December 29, 2017. In addition, the Company recognized non-cash impairment charges of $9.1 million associated with certain unproved properties in the Cottonwood Gulch area of the Piceance Basin and $2.1 million associated with certain non-core unproved properties in the DJ Basin for the year ended December 31, 2017.

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. Natural gas and NGLs are converted to an oil equivalent, Boe, at the standard rate of six Mcf to one Boe and forty-two gallons to one Boe, respectively. Estimated future dismantlement, restoration and abandonment costs are taken into consideration by this calculation.

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

	As of December 31,
	2019		2018
	(in thousands)
Accrued drilling, completion and facility costs	$	25,667	$	69,830
Accrued lease operating, gathering, transportation and processing expenses		8,046		6,970
Accrued general and administrative expenses		6,612		8,774
Accrued interest payable		6,832		6,758
Accrued merger transaction expenses		—		550
Trade payables		17,488		31,057
Operating lease liability		1,287		—
Other		5,706		7,440
Total accounts payable and accrued liabilities	$	71,638	$	131,379

Environmental Liabilities. Environmental expenditures that relate to an existing condition caused by past operations and that do not contribute to current or future revenue generation are expensed. Environmental liabilities are accrued when environmental assessments and/or clean-ups are probable, and the costs can be reasonably estimated. Recent case law in Wyoming has exposed the Company to potential obligations for plugging and abandoning wells, and associated reclamation, for assets that were sold to other industry parties in prior years. If such third parties become unable to fulfill their contractual obligations to the Company as provided for in purchase and sale agreements, regulatory agencies and landowners may demand that the Company perform such activities. The Company recognized $0.3 million and $1.9 million associated with these obligations in other operating expenses in the Consolidated Statement of Operations for the years ended December 31, 2019 and 2018, respectively.

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 December 31, 2019, 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 thus recorded in oil, gas and NGL production revenues in the 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 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.

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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 Consolidated Balance Sheets as assets or liabilities.

Income Taxes. Income taxes are provided for the tax effects of transactions reported in the financial statements and consist of taxes currently payable plus deferred income taxes related to certain income and expenses recognized in different periods for financial and income tax reporting purposes. Deferred income tax assets and liabilities represent the future tax return consequences of those differences, which will either be taxable or deductible when assets are recovered or liabilities are settled. Deferred income taxes also include tax credits and net operating losses that are available to offset future income taxes. Deferred income taxes are measured by applying currently enacted tax rates. A valuation allowance is recorded if it is more likely than not that all or some portion of the Company’s deferred tax assets will not be realized. The Company regularly assesses the realizability of the deferred tax assets considering all positive and negative evidence, including scheduled reversals of deferred tax liabilities, projected future taxable income, planning strategies and results of recent operations. The assumptions about future taxable income require significant judgment to determine if a valuation allowance is required. Changes to the Company’s development plans, changes in market prices for hydrocarbons, changes in operating results, or other factors could change the valuation allowance in future periods, resulting in recognition of 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 December 31, 2019 or 2018.

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

Earnings/Loss Per Share. Basic net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding during each period. Diluted net income (loss) per common share is calculated by dividing net income (loss) attributable to common stock by the weighted average number of common shares outstanding and other dilutive securities. Potentially dilutive securities for the diluted net income per common share calculations consist of nonvested shares of common stock. The dilutive net income per common share excludes the anti-dilutive effect of 8,159 nonvested shares of common stock for the year ended December 31, 2018. The Company was in a net loss position for the years ended December 31, 2019 and 2017, therefore, all potentially dilutive securities were anti-dilutive.

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

	Year Ended December 31,
	2019			2018		2017
	(in thousands, except per share amounts)
Net income (loss)	$	(134,830	)	$	121,220	$	(138,225	)
Basic weighted-average common shares outstanding in period		4,208			3,766		1,537
Add dilutive effects of stock options and nonvested equity shares of common stock		—			19		—
Diluted weighted-average common shares outstanding in period		4,208			3,785		1,537
Basic net income (loss) per common share	$	(32.04	)	$	32.19	$	(89.92	)
Diluted net income (loss) per common share	$	(32.04	)	$	32.03	$	(89.92	)

Industry Segment and Geographic Information. The Company operates in one industry segment, which is the development and production of crude oil, natural gas and NGLs, and all of the Company’s operations are conducted in the continental United States. Consequently, the Company currently reports as a single industry segment.

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

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

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

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

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

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

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

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

The adoption of ASC 842 resulted in the recognition of right-of-use assets of $8.6 million, and current and noncurrent lease liabilities of $0.3 million and $13.7 million, respectively, on the Consolidated Balance Sheet as of January 1, 2019. The difference between the right-of-use assets and the total lease liability was related to lease incentives and deferred rent balances of $5.4 million, which were required to be netted against the right-of-use assets as of the implementation date of January 1, 2019. The Company’s leases include office leases and other equipment, all classified as operating leases. The adoption of ASC 842 had no impact on the Company’s Consolidated Statements of Operations or Cash Flows. See Note 13 for additional information.

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3. Supplemental Disclosures of Cash Flow Information

Supplemental cash flow information is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Cash paid for interest	$	55,470		$	50,063		$	61,295
Cash paid for income taxes		—			—			—
Cash paid for amounts included in the measurements of lease liabilities:
Cash paid for operating leases		1,315
Non-cash operating activities:
Right-of-use assets obtained in exchange for lease obligations
Operating leases (1)		14,999
Supplemental disclosures of non-cash investing and financing activities:
Accrued liabilities - oil and gas properties		28,130			98,346			43,980
Change in asset retirement obligations, net of disposals		(5,538	)		10,778			5,376
Fair value of debt exchanged for common stock		—			—			48,992
Retirement of treasury stock		(1,729	)		(1,535	)		(1,253	)
Properties exchanged in non-cash transactions		4,561			—			13,323
Issuance of common stock for Merger		—			484,000			—

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

4. Mergers, Acquisitions, Exchanges and Divestitures

2019 Divestiture

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

2018 Merger with Fifth Creek Energy Operating Company, LLC

On March 19, 2018, the Company completed the Merger with Fifth Creek. The Merger was effected through the issuance of 2 million shares of the Company’s common stock (100 million shares on a pre-split basis, see Note 16), with a fair value of $484.0 million on the date of closing, and the repayment of $53.9 million of Fifth Creek debt. In connection with the Merger, the Company incurred costs of $4.5 million, $8.0 million and $8.7 million of severance, consulting, advisory, legal and other merger-related fees, all of which were expensed and included in merger transaction expense in the Company’s Consolidated Statement of Operations for the years ended December 31, 2019, 2018 and 2017, respectively.

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Purchase Price Allocation

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

	March 19, 2018
	(in thousands)
Purchase Price:
Fair value of common stock issued	$	484,000
Plus: Repayment of Fifth Creek debt		53,900
Total purchase price		537,900
Plus Liabilities Assumed:
Accounts payable and accrued liabilities		25,782
Current unfavorable contract		2,651
Other current liabilities		13,797
Asset retirement obligations		7,361
Long-term deferred tax liability		137,707
Long-term unfavorable contract		4,449
Other noncurrent liabilities		2,354
Total purchase price plus liabilities assumed	$	732,001
Fair Value of Assets Acquired:
Cash		543
Accounts receivable		7,831
Oil and Gas Properties:
Proved oil and gas properties		105,702
Unproved oil and gas properties		609,568
Asset retirement obligations		7,361
Furniture, equipment and other		931
Other noncurrent assets		65
Total asset value	$	732,001

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

The results of operations attributable to the merged companies are included in the Consolidated Statements of Operations beginning on March 19, 2018. The Company generated revenues of approximately $59.4 million from the Fifth Creek assets during the year ended December 31, 2018 and expenses of approximately $44.2 million during the year ended December 31, 2018.

Pro Forma Financial Information

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

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Additionally, pro forma earnings for the years ended December 31, 2019, 2018 and 2017 were adjusted to exclude merger-related costs of $4.5 million, $8.0 million and $8.7 million incurred by the Company for the years ended December 31, 2019, 2018 and 2017, respectively, and $4.0 million and $2.2 million for the years ended December 31, 2018 and 2017, respectively, incurred by Fifth Creek. The pro forma results of operations do not include any cost savings or other synergies that may have occurred as a result of the acquisition or any estimated costs that have been incurred by the Company to integrate the Fifth Creek assets. The pro forma condensed combined financial information has been included for comparative purposes and is not necessarily indicative of the results that might have actually occurred had the acquisition taken place on January 1, 2017; furthermore, the financial information is not intended to be a projection of future results.

	Year Ended December 31,
	2019			2018		2017
	(in thousands, except per share data)
Revenues	$	452,659		$	468,949	$	291,991
Net Income (Loss)		(131,407	)		125,281		(143,530	)
Net Income (Loss) per Common Share, Basic		(31.00	)		30.00		(40.50	)
Net Income (Loss) per Common Share, Diluted		(31.00	)		30.00		(40.50	)

2017 Acquisitions, Exchanges and Divestitures

On February 28, 2017, the Company acquired acreage in the DJ Basin for $11.6 million, after final closing adjustments. The transaction was considered an asset acquisition and therefore the properties were recorded based on the fair value of the total consideration transferred on the acquisition date and transaction costs were capitalized as a component of the cost of the assets acquired. The acquisition included $9.1 million and $11.2 million of proved and unevaluated properties, respectively, and asset retirement obligations of $8.7 million.

During the year ended December 31, 2017, the Company completed two acreage exchange transactions to consolidate certain acreage positions in the DJ Basin. Pursuant to the transactions, the Company exchanged leasehold interests in certain proved undeveloped acreage. The Company’s future cash flows are not expected to significantly change as a result of the exchange transactions, therefore, the non-monetary exchanges were measured based on the carrying values and not on the fair values of the assets exchanged.

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On December 29, 2017, the Company completed the sale of its remaining non-core assets in the Uinta Basin. The Company received $101.3 million in cash proceeds, after final closing adjustments in 2018. In addition to the cash proceeds, the Company recognized non-cash proceeds of $4.8 million related to relief from the Company’s asset retirement obligation. During the year ended December 31, 2017, the Company recognized a proved property impairment of $37.9 million with respect to these properties in the Consolidated Statement of Operations. During the year ended December 31, 2018, the Company recognized an additional loss on sale of $1.0 million with respect to these properties in the Consolidated Statement of Operations. The carrying amounts by major asset class within the disposal group for the Uinta Basin are summarized below (in thousands):

Assets:
Proved oil and gas properties	$	409,957
Unproved oil and gas properties, excluded from amortization		397
Furniture, equipment and other		1,593
Accumulated depreciation, depletion, amortization and impairment		(304,939	)
Total assets		107,008
Liabilities:
Asset retirement obligations		4,773
Total liabilities		4,773
Net assets	$	102,235

5. Long-Term Debt

The Company’s outstanding debt is summarized below:

			As of December 31, 2019							As of December 31, 2018
	Maturity Date		Principal		Debt Issuance Costs			Carrying Amount		Principal		Debt Issuance Costs			Carrying Amount
			(in thousands)
Amended Credit Facility (1)		September 14, 2023	$	140,000	$	—		$	140,000	$	—	$	—		$	—
7.0% Senior Notes (2)		October 15, 2022		350,000		(2,372	)		347,628		350,000		(3,210	)		346,790
8.75% Senior Notes (3)		June 15, 2025		275,000		(3,717	)		271,283		275,000		(4,403	)		270,597
Lease Financing Obligation (4)		August 10, 2020		—		—			—		1,859		—			1,859
Total Debt			$	765,000	$	(6,089	)	$	758,911	$	626,859	$	(7,613	)	$	619,246
Less: Current Portion of Long-Term Debt (5)				—		—			—		1,859		—			1,859
Total Long-Term Debt			$	765,000	$	(6,089	)	$	758,911	$	625,000	$	(7,613	)	$	617,387

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

(2) The aggregate estimated fair value of the 7.0% Senior Notes was approximately $335.0 million and $329.7 million as of December 31, 2019 and 2018, respectively, based on reported market trades of these instruments.

(3) The aggregate estimated fair value of the 8.75% Senior Notes was approximately $251.2 million and $264.7 million as of December 31, 2019 and 2018, respectively, based on reported market trades of these instruments.

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

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

Amended Credit Facility

On September 14, 2018, the Company entered into a fourth amended and restated credit facility (the “Amended Credit Facility”), which, among other things, provides for a maximum credit amount of $1.5 billion, an initial elected commitment amount of $500.0 million and an initial borrowing base of $500.0 million. Due to the amendment, the Company recognized a loss on extinguishment of debt of $0.3 million on the Consolidated Statements of Operations for the year ended December 31, 2018. As credit support for future payment 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 of the Amended Credit Facility as of December 31, 2019 to $334.0 million. The Company had $140.0 million and zero outstanding borrowings under the Amended

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Credit Facility as of December 31, 2019 and 2018, respectively. 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 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 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% to 0.5%. The applicable margin and the unused commitment fee rate are determined based on borrowing base utilization. The weighted average annual interest rate incurred on the Amended Credit Facility was 4.0% for the year ended December 31, 2019.

The borrowing base under the Amended Credit Facility is determined at the discretion of the lenders, based on the collateral value of the Company’s proved reserves that have been mortgaged to the lenders, and is subject to regular re-determination on or about April 1 and October 1 of each year, as well as following any property sales. Borrowing bases are computed based on proved oil, natural gas and NGL reserves, hedge positions and estimated future cash flows from the reserves calculated using future commodity pricing provided by the Company’s lenders, as well as any other outstanding debt. Lower commodity prices could result in a decreased borrowing base.

The Amended Credit Facility contains certain financial covenants. The Company is currently in compliance with all financial covenants and has complied with all financial covenants since issuance. If the Company fails to comply with the covenants or other terms of any agreements governing the Company’s debt, the lenders under the Amended Credit Facility and holders of the Company’s senior notes may have the right to accelerate the maturity of the relevant debt and foreclose upon the collateral, if any, securing that debt. The occurrence of any such event would adversely affect the Company’s financial condition.

7.0% Senior Notes Due 2022

The Company’s $350.0 million aggregate principal amount 7.0% Senior Notes mature on October 15, 2022 at par, unless earlier redeemed or purchased by the Company. Interest is payable in arrears semi-annually on April 15 and October 15 of each year. The 7.0% Senior Notes are senior unsecured obligations and rank equal in right of payment with all of the Company’s other existing and future senior unsecured indebtedness, including the 8.75% Senior Notes.

The 7.0% Senior Notes are redeemable at the Company’s option at redemption prices of 101.167% and 100.000% of the principal amount on or after October 15, 2019 and 2020, respectively.

8.75% Senior Notes due 2025

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

The 8.75% Senior Notes will become redeemable at the Company’s option on or after June 15, 2020, 2021, 2022 and 2023 at redemption prices of 106.563%, 104.375%, 102.188% and 100.000% of the principal amount, respectively. Prior to June 15, 2020, the Company may use proceeds of an equity offering to redeem up to 35% of the principal amount at a redemption price of 108.750% of the principal amount. In addition, prior to June 15, 2020, the Company may redeem the notes at a redemption price equal to 100.000% of the principal amount plus a specified “make-whole” premium.

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

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

Lease Financing Obligation Due 2020

The Company had a lease financing obligation with a balance of $1.9 million as of December 31, 2018 resulting from the Company’s sale and subsequent lease back of certain compressors and related facilities owned by the Company (the “Lease Financing Obligation”). On February 10, 2019, the Company elected to purchase the equipment under the early buyout option for $1.8 million.

2017 Debt Transactions

Due to the redemption of the Company’s 5.0% Convertible Notes and 7.625% Senior Notes on May 30, 2017 with the proceeds from its 8.75% Senior Notes issued on April 28, 2017, the Company recognized a $7.9 million loss on extinguishment of debt on the Consolidated Statement of Operations for the year ended December 31, 2017.

6. Asset Retirement Obligations

A reconciliation of the Company’s asset retirement obligations for the year ended December 31, 2019, 2018 and 2017 is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Beginning of period	$	29,655		$	17,586		$	11,238
Liabilities incurred (1)(2)		2,863			10,649			10,683
Liabilities settled		(1,682	)		(1,630	)		(1,063	)
Disposition of properties		(7,668	)		(351	)		(5,138	)
Accretion expense		1,592			1,291			972
Revisions to estimate		949			2,110			894
End of period	$	25,709		$	29,655		$	17,586
Less: Current asset retirement obligations		2,218			2,325			1,489
Long-term asset retirement obligations	$	23,491		$	27,330		$	16,097

(1) The year ended December 31, 2018 includes $7.4 million associated with properties acquired in the Merger. See Note 4 for additional information regarding the Merger.

(2) The year ended December 31, 2017 includes $8.7 million associated with properties acquired in the DJ Basin. See Note 4 for additional information regarding this acquisition.

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7. Fair Value Measurements

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

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

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

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

Assets and Liabilities Measured at Fair Value on a Recurring Basis

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

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

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

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

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

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

	Level 1		Level 2		Level 3		Total
	(in thousands)
As of December 31, 2019
Financial Assets
Cash equivalents	$	—	$	—	$	—	$	—
Deferred compensation plan		2,033		—		—		2,033
Commodity derivatives		—		8,890		—		8,890
Financial Liabilities
Commodity derivatives		—		10,056		—		10,056
As of December 31, 2018
Financial Assets
Cash equivalents		12,188		—		—		12,188
Deferred compensation plan		1,392		—		—		1,392
Commodity derivatives		—		109,494		—		109,494
Financial Liabilities
Commodity derivatives		—		1,039		—		1,039

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

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

Oil and gas properties – Oil and gas property costs are evaluated for impairment and reduced to fair value when there is an indication that the carrying costs may not be recoverable. If an impairment is necessary, the fair value is estimated by using either a market approach based on recent sales prices of comparable properties and/or indications from marketing activities or by using the income valuation technique, which involves calculating the present value of future net revenues. The present value, net of estimated operating and development costs, is calculated using estimates of reserves, future commodity pricing, future production estimates, anticipated capital expenditures and various discount rates commensurate with the risk and current market conditions associated with realizing the projected cash flows, predominantly all of which are designated as Level 3 inputs within the fair value hierarchy. The Company did not fair value any of its oil and gas properties as of December 31, 2019 and 2018.

Purchase price allocation – The Merger was accounted for as a business combination, using the acquisition method. The allocation of the total purchase price to the identifiable assets acquired and the liabilities assumed was based on the fair values at the acquisition date. See Note 4 for additional information regarding the fair value of the Merger.

Additional Fair Value Disclosures

Long-term Debt – Long-term debt is not presented at fair value on the Consolidated Balance Sheets, as it is recorded at carrying value, net of unamortized debt issuance costs. The fair values of the Company’s fixed rate 7.0% Senior Notes and 8.75% Senior Notes totaled $586.2 million and $594.4 million as of December 31, 2019 and 2018, respectively. The fair values of the Company’s fixed rate Senior Notes are based on active market quotes, which represent Level 1 inputs.

There is no active, public market for the Amended Credit Facility. The recorded value of the Amended Credit Facility approximates its fair value due to its floating rate structure based on the LIBOR spread, secured interest, and the Company’s borrowing base utilization. The Amended Credit Facility had a balance of $140.0 million and zero as of December 31, 2019 and 2018, respectively. The Lease Financing Obligation fair value of $1.8 million as of December 31, 2018 was measured based on market-based parameters of comparable term secured financing instruments. On February 10, 2019, the Company elected to purchase the equipment. See Note 5 for additional information. The fair value measurements for the Amended Credit Facility and Lease Financing Obligation represent Level 2 inputs.

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8. Derivative Instruments

The Company uses financial derivative instruments as part of its price risk management program to achieve a more predictable cash flow from its production revenues by reducing its exposure to commodity price fluctuations. The Company has entered into financial commodity swap contracts and costless collars related to the sale of a portion of the Company’s production. The Company does not enter into derivative instruments for speculative or trading purposes.

In addition to financial contracts, the Company may at times be party to various physical commodity contracts for the sale of oil, natural gas and NGLs that have varying terms and pricing provisions. These physical commodity contracts qualify for the normal purchase and normal sale exception and, therefore, are not subject to hedge or mark-to-market accounting. The 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 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 Consolidated Balance Sheets as of the dates indicated.

	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 non-current		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)
Derivative 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	)
	As of December 31, 2018
Balance Sheet	Gross Amounts of Recognized Assets			Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet
				(in thousands)
Derivative assets current	$	82,205		$	(1,039	)(1)	$	81,166
Derivative assets non-current		27,289			—			27,289
Total derivative assets	$	109,494		$	(1,039	)	$	108,455
	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet			Net Amounts of Liabilities Presented in the Balance Sheet
				(in thousands)
Derivative liabilities	$	(1,039	)	$	1,039	(1)	$	—
Other noncurrent liabilities		—			—			—
Total derivative liabilities	$	(1,039	)	$	1,039		$	—

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

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As of December 31, 2019, the Company had swap contracts in place to hedge the following volumes for the periods indicated:

	For the Year 2020				For the Year 2021
	Derivative Volumes		Weighted Average Price		Derivative Volumes		Weighted Average Price
Oil (Bbls)		5,857,500	$	58.32		911,000	$	53.42

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 December 31, 2019. Although notional amounts are used to express the volume of these contracts, the amounts potentially subject to credit risk in the event of non-performance by the counterparties are substantially smaller. The creditworthiness of counterparties is subject to continual review by management, and the Company believes all of these institutions currently are acceptable credit risks. Full performance is anticipated, and the Company has no past due receivables from any of its counterparties.

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

9. Income Taxes

The (expense) benefit for income taxes consisted of the following for the periods indicated:

	Year Ended December 31,
	2019		2018			2017
	(in thousands)
Current:
Federal	$	—	$	—		$	1,402
State		—		—			—
Deferred:
Federal		35,806		(1,777	)		—
State		6,310		(50	)		—
Total	$	42,116	$	(1,827	)	$	1,402

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Income tax (expense) benefit differed from the amounts computed by applying the U.S. federal income tax rate of 21% to pretax income for the years ended December 31, 2019 and 2018 and 35% to pretax income for the year ended December 31, 2017 from continuing operations as a result of the following:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Income tax (expense) benefit at the federal statutory rate	$	37,159		$	(25,840	)	$	48,869
State income tax (expense) benefit, net of federal tax effect		6,002			(5,144	)		4,030
Change in federal tax rate		—			—			(64,949	)
Refundable AMT credits		—			—			1,402
Nondeductible equity-based compensation		(1,895	)		(3,101	)		(13,655	)
Nondeductible costs in connection with Merger		—			(2,545	)		—
Other permanent items		(157	)		(418	)		(37	)
Change in valuation allowance		628			36,321			(35,684	)
Change in valuation allowance due to TCJA		—			—			64,949
Change in valuation allowance - Section 382		—			64,994			—
Change in apportioned state tax rates		275			(723	)		(1,086	)
Eliminate UT jurisdiction NOL’s and credits		—			—			(2,647	)
Change in ownership - Section 382		—			(64,994	)		—
Other, net		104			(377	)		210
Income tax (expense) benefit	$	42,116		$	(1,827	)	$	1,402

On the date of the Merger, the Fifth Creek assets were acquired in a nontaxable transaction pursuant to Section 351 of the Internal Revenue Code. Accordingly, a deferred tax liability of $137.7 million was recorded to reflect the difference between the fair value recorded and the income tax basis of the assets acquired and liabilities assumed.

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The tax effects of temporary differences that give rise to significant components of the deferred tax assets and deferred tax liabilities as of December 31, 2019 and 2018 are presented below:

	As of December 31,
	2019			2018
	(in thousands)
Long-term:
Deferred tax assets:
Net operating loss carryforward	$	112,409		$	112,898
Stock-based compensation		1,368			1,962
Deferred rent		—			628
Financing obligation		2,163			1,174
Accrued expenses		38			250
Derivative instruments		287			—
Other assets		148			2,409
Capital loss carryforward		890			1,028
Less: Valuation allowance		(12,587	)		(13,215	)
Total long-term deferred tax assets		104,716			107,134
Deferred tax liabilities:
Oil and gas properties		(201,396	)		(219,390	)
Long-term derivative instruments		—			(26,700	)
Prepaid expenses		(462	)		(374	)
Deferred compensation		(276	)		(204	)
Total long-term deferred tax assets (liabilities)		(202,134	)		(246,668	)
Net long-term deferred tax assets (liabilities)	$	(97,418	)	$	(139,534	)

In connection with the Merger, the Company had a greater than 50% ownership change pursuant to Section 382 of the Internal Revenue Code. As a result of the ownership change, the Company’s ability to use pre-change net operating losses (“NOLs”) and credits against post-change taxable income is limited to an annual amount plus any built-in gains recognized within five years of the ownership change. The Company’s annual limitation amount is approximately $11.7 million and the net unrealized built-in gain is projected to be $176.9 million. The Company has reduced its federal and state NOLs by $276.1 million and $14.0 million, respectively, and eliminated its state tax credits by $8.2 million to reflect the expected impact of the Section 382 limitation. Deferred tax assets and the corresponding valuation allowance have been reduced by $65.0 million for the expected tax effect of the Section 382 limitation. As of December 31, 2019, the Company projected approximately $455.8 million and $456.2 million of federal and state NOLs, respectively. The federal NOLs begin to expire in 2025 and the state NOLs begin to expire in 2029.

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

In assessing the ability to realize the benefit of the deferred tax assets, management must consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. Management considers all available evidence (both positive and negative) in determining whether a valuation allowance is required. Such evidence includes the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment, and judgment is required in considering the relative weight of negative and positive evidence. In regard to the Company’s deferred tax assets, the Company considered all available evidence in assessing the need for a valuation allowance.

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The Company accounts for uncertainty in income taxes for tax positions taken or expected to be taken in a tax return. 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, based on the technical merits. The Company did not have any additions, reductions or settlements of unrecognized tax benefits. In 2019, the Company generated 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. As of December 31, 2019, the Company did not have any accrued interest or penalties associated with any unrecognized tax benefits, nor was any interest expense recognized during the current year.

The Company and its subsidiaries file income tax returns in the U.S. federal jurisdiction and in various states. With few exceptions, the Company is subject to U.S. federal tax examination for years 2016 through 2019 and is subject to state tax examination for years 2015 through 2019.

10. Stockholders’ Equity

Common and Preferred Stock. The Company’s authorized capital structure consists of 75,000,000 shares of preferred stock, par value $0.001 per share, and 8,000,000 shares of common stock, par value $0.001 per share. There are no issued and outstanding shares of preferred stock.

In March 2018, the Company completed the Merger with Fifth Creek. Pursuant to the Merger Agreement, each share of Bill Barrett common stock, par value $0.001 per share (the “BBG Common Stock”), issued and outstanding immediately prior to the closing of the Merger was converted into one share of the Company’s common stock and all outstanding equity interests in Fifth Creek, in the aggregate, were converted into 2 million shares of the Company’s common stock (100 million shares on a pre-split basis, see Note 16). In addition, all options to purchase shares of BBG Common Stock and all common stock awards and performance-based cash unit awards relating to BBG Common Stock that were outstanding immediately prior to the closing of the Merger were generally converted into corresponding awards relating to shares of the Company’s common stock on the same terms and conditions (excluding performance conditions) as applied prior to the closing of the Merger (with 2016 and 2017 Program performance-based cash units converting into time-based common stock awards based on actual performance for the 2016 program and target performance for the 2017 program through the closing date). See Note 11 for additional information on equity compensation.

In March 2018, the Company terminated the Equity Distribution Agreement, dated as of June 2015, by and between the Company and Goldman, Sachs and Co., which established an “at-the-market” program for sales of common stock from time to time. The agreement was terminable at will upon written notification by the Company with no penalty. No shares had been sold pursuant to this Agreement.

In December 2017, the Company completed a public offering of its common stock, selling 464,111 shares at a price of $250.00 per share, par value $0.001 per share. The sale included the partial exercise of 44,111 shares of common stock by the underwriters from their option to purchase 63,000 shares of common stock. Net proceeds from the sale, after deducting fees and estimated expenses, were approximately $110.8 million.

In December 2017, the Company issued 217,260 shares of common stock pursuant to the a debt exchange with a holder of the Company’s 7.0% Senior Notes. The holder exchanged $50.0 million principal amount of the 7.0% Senior Notes for 217,260 newly issued shares of the Company’s common stock.

Treasury Stock. The Company may occasionally acquire treasury stock, which is recorded at cost, in connection with the vesting and exercise of stock-based awards or for other reasons. As of December 31, 2019, all treasury stock held by the Company was retired.

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The following table reflects the activity in the Company’s common and treasury stock for the periods indicated:

	Year Ended December 31,
	2019			2018			2017
Common Stock Outstanding:
Shares at beginning of period		4,249,543			2,207,272			1,514,427
Shares issued for directors’ fees		3,164			3,751			1,370
Shares issued for nonvested shares of common stock		36,954			46,642			16,032
Shares issued for debt exchange		—			—			217,260
Shares issued for equity offering		—			—			464,111
Shares issued for merger, common stock		—			2,000,000			—
Shares retired or forfeited		(16,270	)		(8,122	)		(5,928	)
Shares at end of period		4,273,391			4,249,543			2,207,272
Treasury Stock:
Shares at beginning of period		—			—			—
Treasury stock acquired		14,380			5,716			4,868
Treasury stock retired		(14,380	)		(5,716	)		(4,868	)
Shares at end of period		—			—			—

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

The Company maintains various stock-based compensation plans and other employee benefit plans 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:

	Year Ended December 31,
	2019		2018		2017
	(in thousands)
Nonvested common stock (1)	$	6,601	$	6,036	$	5,852
Nonvested common stock units (1)		1,177		1,138		690
Nonvested performance-based shares		—		—		558
Nonvested performance cash units (2)(3)		844		52		1,189
Total	$	8,622	$	7,226	$	8,289

(1) Unrecognized compensation cost as of December 31, 2019 was $5.9 million related to grants of nonvested shares of common stock and common stock units that are expected to be recognized over a weighted-average period of 1.6 years.

(2) The nonvested performance-based cash units are accounted for as liability awards with $1.4 million in accounts payable and accrued liabilities as of December 31, 2017, and $1.2 million, $0.3 million and $3.0 million in other noncurrent liabilities as of December 31, 2019, 2018 and 2017, respectively, in the 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.

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Nonvested Equity and Cash Awards. In May 2012, the Company’s stockholders approved and adopted its 2012 Equity Incentive Plan (the “2012 Incentive Plan”). The purpose of the 2012 Incentive Plan is to enhance the Company’s ability to attract and retain officers, employees and directors and to provide such persons with an interest in the Company aligned with the interests of stockholders. The 2012 Incentive Plan provides for the grant of awards including performance units, performance shares, share awards, share units, restricted stock, cash incentive, stock appreciation rights or SARS, and stock options (including incentive stock options and non-qualified stock options).

In February 2018, the Company’s stockholders approved an amendment to the 2012 Incentive Plan (the “Amendment”). Pursuant to the Amendment, the Company is authorized to issue 130,000 shares, less any shares issued under the 2012 Incentive Plan on or after the Amendment adoption date, and plus any shares that again become available for grant. Shares underlying grants that expire without being exercised or are forfeited are available for grant under the 2012 Incentive Plan; however, shares withheld by the Company to satisfy any tax withholding obligation will not be available for future issuance. As of December 31, 2019, 46,345 shares remain available for grant under the 2012 Incentive Plan.

Currently, the Company’s practice is to issue new shares upon stock option exercise. The Company does not expect to repurchase any shares in the open market or issue treasury shares to settle any such exercises. For the years ended December 31, 2019, 2018 and 2017, the Company did not pay cash to repurchase any stock option exercises.

A summary of share-based option activity under all the Company’s plans as of December 31, 2019, and changes during the year then ended, is presented below:

Option Awards	Shares			Weighted Average Exercise Price
Outstanding at January 1, 2019		2,537		$	1,362.50
Granted (1)		—			—
Exercised		—			—
Forfeited or expired		(2,537	)		1,362.50
Outstanding at December 31, 2019 (2)		—			—

(1) The Company has not granted any share-based option awards since 2012.

(2) At December 31, 2019, there are no outstanding share-based option awards.

There have been no stock options exercised for the years ended December 31, 2019, 2018 and 2017.

The Company grants service-based shares of common stock to employees, which generally vest ratably over a three year service period. These awards are measured at fair value based on the closing price of the Company’s common stock on the date of grant. A summary of the Company’s nonvested common stock awards for the years ended December 31, 2019, 2018 and 2017 is presented below:

	Year Ended December 31,
	2019					2018					2017
Nonvested Common Stock Awards	Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		58,243		$	263.50		27,897		$	348.48		23,382		$	466.50
Granted		36,954			131.95		23,716			273.50		15,823			299.50
Modified (1)		—			—		22,926			242.00		—			—
Vested (2)		(33,939	)		249.50		(13,890	)		412.00		(10,268	)		537.00
Forfeited or expired		(1,889	)		245.50		(2,406	)		296.50		(1,040	)		395.50
Outstanding at December 31,		59,369			190.74		58,243			263.50		27,897			348.48

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

(2) The fair value of common stock awards vested was $4.1 million, $3.7 million and $2.9 million for the years ended December 31, 2019, 2018 and 2017, respectively.

The Company grants service-based shares of common stock units to non-employee or outside directors, which generally vest over a one year service period. These awards are measured at fair value based on the closing price of the Company’s common stock on the date of grant. The common stock units are the directors’ annual compensation and are settled in common stock on a one-to-one basis. Common stock units have only been granted to outside directors. A summary of the Company’s nonvested common stock units for the years ended December 31, 2019, 2018 and 2017 is presented in the table below:

	Year Ended December 31,
	2019					2018					2017
Nonvested Common Stock Unit Awards	Units			Weighted Average Grant Date Fair Value		Units			Weighted Average Grant Date Fair Value		Units			Weighted Average Grant Date Fair Value
Outstanding at January 1,		6,224		$	362.97		5,451		$	318.34		2,943		$	504.50
Granted		12,862			93.78		4,525			291.50		3,878			178.00
Vested (1)		(3,164	)		271.99		(3,752	)		212.00		(1,370	)		321.00
Forfeited or expired		—			—		—			—		—			—
Outstanding at December 31,		15,922			163.61		6,224			362.97		5,451			318.34

(1) The fair value of common stock unit awards vested was $0.3 million, $1.1 million and $0.2 million for the years ended December 31, 2019, 2018 and 2017, respectively.

For the years ended December 31, 2019, 2018 and 2017, the Company granted performance-based cash units that will settle in cash. These awards are accounted for as liability awards and are measured at fair value at each reporting date. A summary of the Company’s nonvested performance-based cash units for the years ended December 31, 2019, 2018 and 2017 is presented below:

	Year Ended December 31,
	2019					2018					2017
Nonvested Performance-Based Cash Unit Awards	Units			Weighted Average Fair Value		Units			Weighted Average Fair Value		Units			Weighted Average Fair Value
Outstanding at January 1,		18,191					30,962					18,847
Granted		40,530					18,706					13,381
Performance goal adjustment (1)		—					226					—
Modified (2)		—					(24,230	)				—
Vested (3)		—					(5,733	)				—
Forfeited or expired		(7,200	)				(1,740	)				(1,266	)
Outstanding at December 31,		51,521		$	79.50		18,191		$	61.50		30,962		$	255.00

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

(2) Due to the closing of the Merger, the 2016 and 2017 Performance Cash Programs were converted from nonvested performance-based cash units to nonvested common stock awards, resulting in a decrease in nonvested performance-based cash units for the year ended December 31, 2018. The 2016 Program converted based on performance through March 19, 2018, which resulted in 89% of the units converting to nonvested common stock awards or a reduction of 1,303 units converting to nonvested common stock awards.

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(3) The fair value of performance-based cash unit awards vested was $1.5 million for the year ended December 31, 2018. No awards vested in 2019 or 2017.

For the year ended December 31, 2014 and prior, the Company granted performance-based shares that settled in common stock. These awards are accounted for as equity awards. The market-based goals or total shareholder return (“TSR”) goals associated with these awards are valued at each reporting date using a Monte Carlo simulation. The non-market-based goals are measured at fair value based on the closing price of the Company’s common stock on the date of grant. A summary of the Company’s vested performance-based shares of common stock for the years ended December 31, 2019, 2018 and 2017 is presented below:

	Year Ended December 31,
	2019				2018				2017
Nonvested Performance-Based Common Stock Awards	Shares		Weighted Average Grant Date Fair Value		Shares		Weighted Average Grant Date Fair Value		Shares			Weighted Average Grant Date Fair Value
Outstanding at January 1,		—	$	—		—	$	—		3,132		$	977.00
Granted (1)		—		—		—		—		—			—
Performance goal adjustment (2)		—		—		—		—		209			1,222.50
Vested (3)		—		—		—		—		(3,320	)		1,222.50
Forfeited or expired		—		—		—		—		(21	)		1,231.00
Outstanding at December 31,		—		—		—		—		—			—

(1) The Company has not granted any performance-based common stock awards since 2014.

(2) The 2014 Program vested at 106.7% of target level and resulted in additional shares vesting in May 2017. These shares are included in the vested line item for the year ended December 31, 2017.

(3) The fair value of performance-based common stock awards vested was $0.6 million for the year ended December 31, 2017. No awards vested in 2019 or 2018.

Performance Cash and Share Programs

2019 Program. In February 2019, the Compensation Committee of the Board of Directors of the Company approved a performance cash program (the “2019 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2022, depending on the level at which the performance goal is achieved. The performance goal, which will be measured over the three-year period ending December 31, 2021, will be the Company’s total shareholder return (“TSR”) based on a matrix measurement of (1) the Company’s absolute performance and (2) the Company’s ranking relative to a defined peer group’s individual TSRs (“Relative TSR”). The Company’s absolute performance is measured against the December 31, 2018 closing share price of $124.50. For the portion of the program based on absolute performance (i) if the Company’s absolute performance is less than 50%, the payout is zero, (ii) if the Company’s absolute performance is 50%, the payout is 50% and (iii) if the Company’s absolute performance is 100%, the payout is 100%, which is the maximum payout for this portion. For the portion of the program based on relative performance (i) if the Company’s Relative TSR is less than 30%, the payout is 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.

2018 Program. In February 2018, the Compensation Committee approved a performance cash program (the “2018 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards contingently vest in February 2021, 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, 2020, 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

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ranking relative to a defined peer group’s individual TSRs (“Relative TSR”). The Company’s absolute performance is measured against the December 29, 2017 closing share price of $256.50. If the Company’s absolute performance is lower than the $256.50 share price, the payout is zero for this portion. If the Company’s absolute performance is greater than the $256.50 share price, the performance cash units will vest 1% for each 1% in growth, up to 150% of the original grant. If the Company’s Relative TSR is less than the median, the payout is zero for this portion. If the Company’s Relative TSR is above the median, the payout is equal to the Company’s percentile rank above the median, up to 50% 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.

2017 Program. In February 2017, the Compensation Committee approved a performance cash program (the “2017 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. In March 2018, upon the Merger closing, each award under the 2017 Program was converted to a nonvested common stock award at 100% of the original award. At the time of the modification, 12,381 units were converted to 12,381 nonvested shares of the Company’s common stock affecting 34 employees. These awards no longer have a performance criterion, but continue to have a service-based criterion through the cliff vest in February 2020. The conversion of the performance-based liability award to a service-based equity award was accounted for as a modification in accordance with ASC 718, Compensation - Stock Compensation. The total incremental compensation cost resulting from the modification was an increase of $0.5 million. The Company recorded an increase to additional paid-in capital (“APIC”) and a decrease to derivative and other noncurrent liabilities of $0.9 million as of December 31, 2018 in the Consolidated Statement of Stockholders’ Equity and the Consolidated Balance Sheets, respectively.

2016 Program. In March 2016, the Compensation Committee approved a performance cash program (the “2016 Program”) granting performance cash units that would settle in cash and were accounted for as liability awards. In March 2018, upon the Merger closing, each award under the 2016 Program was converted to a nonvested common stock award at 89% of the original award based on the Company’s performance through March 19, 2018. At the time of the modification, 11,849 units were converted to 10,546 nonvested shares of the Company’s common stock affecting 23 employees. These awards no longer have a performance criterion, but continued to have a service-based criterion through the cliff vest that occurred in February 2019. The conversion of the performance-based liability award to a service-based equity award was accounted for as a modification in accordance with ASC 718, Compensation - Stock Compensation. The total incremental compensation cost resulting from the modification was zero. The Company recorded an increase to APIC and a decrease to derivative and other noncurrent liabilities of $1.8 million as of December 31, 2018 in the Consolidated Statement of Stockholders’ Equity and the Consolidated Balance Sheets, respectively.

2015 Program. In February 2015, the Compensation Committee approved a performance cash program (the “2015 Program”) granting performance cash units that will settle in cash and are accounted for as liability awards. The performance-based awards vested in May 2018, based on the level at which the performance goals were achieved. The performance goals, which were measured over the three year period ending December 31, 2017, consisted of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in discretionary cash flow per debt adjusted share relative to a defined peer group’s percentage calculation (“DCF per Debt Adjusted Share”) (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals were to vest at 25% or 50%, respectively, of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric were between the threshold and target levels or between the target and stretch levels, the vested number of units was to be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics were not met, no units would vest. In any event, the total number of units that could vest would not exceed 200% of the original number of performance cash units granted. At the end of the three year vesting period, units that did not vest were forfeited. A total of 8,447 units were granted under this program during the year ended December 31, 2015. All compensation expense related to the TSR metric was recognized if the requisite service period is fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric was based on the number of shares expected to vest at the end of the three year period. The Company modified the vest date of these awards from May 2018 to March 2018. Based upon the Company’s performance through 2017, 104.1% or 5,733 units of the 2015 Program vested in March 2018.

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2014 Program. In February 2014, the Compensation Committee approved a performance share program (the “2014 Program”) pursuant to the 2012 Equity Incentive Plan. The awards in this program settled in shares of common stock. The performance-based awards vested in May 2017, based on the level at which the performance goals were achieved. The performance goals, which were measured over the three year period ending December 31, 2016, consisted of the TSR compared to Relative TSR (weighted at 60%) and the percentage change in DCF per Debt Adjusted Share (weighted at 40%). The Relative TSR and DCF per Debt Adjusted Share goals were to vest at 25% of the total award for performance met at the threshold level, 100% at the target level and 200% at the stretch level. If the actual results for a metric were between the threshold and target levels or between the target and stretch levels, the vested number of shares would be prorated based on the actual results compared to the threshold, target and stretch goals. If the threshold metrics were not met, no shares would vest. In any event, the total number of shares of common stock that could vest would not exceed 200% of the original number of performance shares granted. At the end of the three year vesting period, any shares that did not vest were forfeited. A total of 6,313 shares were granted under this program during the year ended December 31, 2014. All compensation expense related to the TSR metric was recognized if the requisite service period was fulfilled, even if the market condition was not achieved. All compensation expense related to the DCF per Debt Adjusted Share metric was based on the number of shares expected to vest at the end of the three year period. Based upon the Company’s performance through 2016, 106.7% or 3,320 shares of the 2014 Program vested in May 2017.

Other Employee Benefits-401(k) Savings Plan. The Company has an employee-directed 401(k) savings plan (the “401(k) Plan”) for all eligible employees over the age of 21. Under the 401(k) Plan, employees may make voluntary contributions based on a percentage of their pretax income, subject to statutory limitations.

The Company matches 100% of each employee’s contribution, up to 6% of the employee’s pretax income in cash. The Company’s cash contributions are fully vested upon the date of match. The Company made matching cash contributions of $1.3 million, $1.2 million and $1.0 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Deferred Compensation Plan. In 2010, the Company adopted a non-qualified deferred compensation plan for certain employees and officers whose eligibility to participate in the plan was determined by the Compensation Committee. The Company makes matching cash contributions on behalf of eligible employees up to 6% of the employee’s cash compensation once the contribution limits are reached in the Company’s 401(k) Plan. All amounts deferred and matched under the plan vest immediately. Deferred compensation, including accumulated earnings on the participant-directed investment selections, is distributable in cash at participant-specified dates or upon retirement, death, disability, change in control or termination of employment.

The table below summarizes the activity in the plan as of December 31, 2019 and 2018, and the Company’s ending deferred compensation liability as of December 31, 2019 and 2018:

	As of December 31,
	2019			2018
	(in thousands)
Beginning deferred compensation liability balance	$	1,392		$	1,749
Employee contributions		276			370
Company matching contributions		150			198
Distributions		(193	)		(806	)
Participant earnings (losses)		408			(119	)
Ending deferred compensation liability balance	$	2,033		$	1,392
Amount to be paid within one year	$	844		$	94
Remaining balance to be paid beyond one year	$	1,189		$	1,298

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The Company has established a rabbi trust to offset the deferred compensation liability and protect the interests of the plan participants. The investments in the rabbi trust seek to offset the change in the value of the related liability. As a result, there is no expected impact on earnings or earnings per share from the changes in market value of the investment assets because the changes in market value of the trust assets are offset by changes in the value of the deferred compensation plan liability. The gains and losses from changes in fair value of the investments are included in interest and other income in the Consolidated Statements of Operations.

The following table represents the Company’s activity in the investment assets held in the rabbi trust as of December 31, 2019 and 2018:

	As of December 31,
	2019			2018
	(in thousands)
Beginning investment balance	$	1,392		$	1,749
Investment purchases		426			568
Distributions		(193	)		(806	)
Earnings (losses)		408			(119	)
Ending investment balance	$	2,033		$	1,392

12. Significant Customers and Other Concentrations

Significant Customers. During 2019, three customers individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. During 2018, four customers individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. During 2017, three customers individually accounted for over 10% of the Company’s oil, gas and NGL production revenues. Collectability is dependent upon the financial stability of each individual company and is influenced by the general economic conditions of the industry. The Company normally sells production to a relatively small number of customers, as is customary in the development and production business. Based on where the Company operates and the availability of other purchasers and markets, the Company believes that its production could be sold in the market in the event that it is not sold to its existing customers. However, in some circumstances, a change in customers may entail significant costs during the transition to a new customer.

Concentrations of Market Risk. The future results of the Company’s oil and gas operations will be affected by the market prices of oil, natural gas and NGLs. A readily available market for oil, natural gas and NGLs in the future will depend on numerous factors beyond the control of the Company, including weather, imports, marketing of competitive fuels, proximity and capacity of oil and gas pipelines and other transportation facilities, any oversupply or undersupply of oil, gas and NGLs, the regulatory environment, the economic environment and other regional, national and international economic and political events, none of which can be predicted with certainty.

The Company operates in the exploration, development and production phase of the oil and gas industry. Its receivables include amounts due from purchasers of oil and gas production and amounts due from joint venture partners for their respective portions of operating expenses and exploration and development costs. The Company believes that no single customer or joint venture partner exposes the Company to significant credit risk. While certain of these customers and joint venture partners are affected by periodic downturns in the economy in general or in their specific segment of the natural gas or oil industry, the Company believes that its level of credit-related losses due to such economic fluctuations has been and will continue to be immaterial to the Company’s results of operations in the long-term. Trade receivables are generally not collateralized. The Company analyzes customers’ and joint venture partners’ historical credit positions and payment histories prior to extending credit and continuously monitors all credit activities.

Concentrations of Credit Risk. Derivative financial instruments that hedge the price of oil, natural gas and NGLs are generally executed with major financial or commodities trading institutions which expose the Company to market and credit

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risks and may, at times, be concentrated with certain counterparties or groups of counterparties. The Company’s policy is to execute financial derivatives only with major, creditworthy financial institutions. The Company has derivative instruments with nine different counterparties, of which all are lenders or affiliates of lenders in the Amended Credit Facility.

The creditworthiness of counterparties is subject to continuing review, 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. Where the counterparty is a lender under the Amended Credit Facility, the counterparty risk is mitigated to the extent that the Company is indebted to such lender under the Amended Credit Facility.

13. Leases

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

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

The Company’s leases have remaining terms of up to 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 rate implicit in the lease, when readily determinable. As the Company’s leases do not provide an implicit rate, the Company utilizes its incremental borrowing rate.

The Company has elected, for all classes of underlying assets, to not apply the balance sheet recognition requirements of ASC 842 to leases with a term of one year or less, and instead, the Company recognizes the lease payments in the income statement on a straight-line basis over the lease term. The Company has also made the election, for certain classes of underlying assets, to combine lease and non-lease components. Therefore, the Company made the election to combine lease and non-lease components for drilling rig and gathering system asset classes. These assets are not reported on the 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 year ended December 31, 2019, lease cost was as follows:

	Year Ended December 31,
Lease Cost	2019
	(in thousands)
Operating lease cost (1)(3)	$	2,239
Short-term lease cost (2)(3)		15,928
Variable lease cost (4)		654
Total lease cost	$	18,821

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

Supplemental balance sheet information related to leases as of December 31, 2019, was as follows:

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

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

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

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

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

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

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

	As of December 31, 2019
	(in thousands)
2020	$	2,056
2021		2,355
2022		2,044
2023		2,024
2024		2,078
Thereafter		7,577
Total	$	18,134
Less: Interest		(3,652	)
Present value of lease liabilities	$	14,482

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

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

14. Commitments and Contingencies

Firm Transportation Agreements. The Company is party to two firm transportation contracts to provide capacity on natural gas pipeline systems. The contracts require the Company to pay minimum volume transportation charges through July 2021 regardless of the amount of pipeline capacity utilized by the Company. These monthly transportation payments are included in unused commitments expense in the 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 December 31, 2019
	(in thousands)
2020	$	23,134
2021		19,778
2022		13,064
2023		14,600
2024		14,640
Thereafter		4,800
Total	$	90,016

Gas Gathering and Processing Agreements. The Company is party to one minimum volume commitment and two reimbursement obligations. The minimum volume commitment requires the Company to deliver a minimum volume of natural gas to a midstream entity for gathering and processing. The contract requires the Company to pay a fee associated with the contracted volumes regardless of the amount delivered. The reimbursement obligations require the Company to pay a monthly gathering and processing fee per Mcf of production to reimburse midstream entities for the 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 these agreements:

101

	As of December 31, 2019
	(in thousands)
2020 (1)	$	4,569
2021		1,997
Thereafter		—
Total	$	6,566

(1) Includes $2.4 million associated with the reimbursement obligations discussed above.

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 December 31, 2019
	(in thousands)
2020	$	3,448
2021		805
2022		805
2023		745
Thereafter		—
Total	$	5,803

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 Consolidated Balance Sheet, Cash Flows or Statements of Operations.

15. Parent and Subsidiary Guarantor

The condensed consolidating financial information as of and for the periods ended December 31, 2019 presents the results of operations, financial position and cash flows of HighPoint Resources Corporation, or parent guarantor, and HighPoint Operating Corporation (f/k/a Bill Barrett), or subsidiary issuer, and Fifth Pocket Production, LLC, a subsidiary guarantor (formed on August 1, 2019), as well as the consolidating adjustments necessary to present HighPoint Resources Corporation’s results on a consolidated basis. The parent guarantor and the subsidiary guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the subsidiary issuer. The indentures governing those securities limit the ability of the subsidiary issuer and the subsidiary guarantor to pay dividends or otherwise provide funding to the parent guarantor.

Prior periods are presented under the structure of the Company prior to the formation of Fifth Pocket Production, LLC.

In September 2018, Circle B Land Company LLC, a 100% owned subsidiary, merged into its parent company, HighPoint Operating Corporation. Prior periods are presented under the structure of the Company prior to the Merger and prior to the elimination of Circle B Land Company LLC. Circle B Land Company LLC and Aurora Gathering, LLC (both of which were 100% owned subsidiaries of the Company), on a joint and several basis, fully and unconditionally guaranteed the debt of Bill Barrett, the parent issuer. On December 29, 2017, the Company completed the sale of its remaining assets in the Uinta Basin, which included the equity of Aurora Gathering, LLC.

102

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

Condensed Consolidating Balance Sheets

	As of December 31, 2019
	Parent Guarantor		Subsidiary Issuer		Subsidiary Guarantor		Intercompany Eliminations			Consolidated
	(in thousands)
Assets:
Cash and cash equivalents	$	—	$	16,449	$	—	$	—		$	16,449
Accounts receivable, net of allowance for doubtful accounts		—		62,098		22		—			62,120
Other current assets		—		7,868		—		—			7,868
Property and equipment, net		—		2,063,798		376		—			2,064,174
Intercompany receivable		—		363		—		(363	)		—
Investment in subsidiaries		1,083,318		34		—		(1,083,352	)		—
Noncurrent assets		—		5,441		—		—			5,441
Total assets	$	1,083,318	$	2,156,051	$	398	$	(1,083,715	)	$	2,156,052
Liabilities and Stockholders’ Equity:
Accounts payable and accrued liabilities	$	—	$	71,638	$	—	$	—		$	71,638
Other current liabilities		—		103,839		1		—			103,840
Intercompany payable		—		—		363		(363	)		—
Long-term debt		—		758,911		—		—			758,911
Deferred income taxes		—		97,418		—		—			97,418
Other noncurrent liabilities		—		40,927		—		—			40,927
Stockholders’ equity		1,083,318		1,083,318		34		(1,083,352	)		1,083,318
Total liabilities and stockholders’ equity	$	1,083,318	$	2,156,051	$	398	$	(1,083,715	)	$	2,156,052

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

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Condensed Consolidating Statements of Operations

	Year Ended December 31, 2019
	Parent Guarantor			Subsidiary Issuer			Subsidiary Guarantor			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	—		$	452,623		$	36		$	—	$	452,659
Operating expenses		—			(424,090	)		(2	)		—		(424,092	)
General and administrative		—			(44,759	)		—			—		(44,759	)
Merger transaction expense		—			(4,492	)		—			—		(4,492	)
Interest expense		—			(58,100	)		—			—		(58,100	)
Interest income and other income (expense)		—			(98,162	)		—			—		(98,162	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		—			(176,980	)		34			—		(176,946	)
(Provision for) Benefit from income taxes		—			42,116			—			—		42,116
Equity in earnings (loss) of subsidiaries		(134,830	)		34			—			134,796		—
Net income (loss)	$	(134,830	)	$	(134,830	)	$	34		$	134,796	$	(134,830	)

	Year Ended December 31, 2018
	Parent Guarantor		Subsidiary Issuer			Intercompany Eliminations			Consolidated
	(in thousands)
Operating and other revenues	$	—	$	453,017		$	—		$	453,017
Operating expenses		—		(319,031	)		—			(319,031	)
General and administrative		—		(45,130	)		—			(45,130	)
Merger transaction expense		—		(7,991	)		—			(7,991	)
Interest expense		—		(52,703	)		—			(52,703	)
Interest income and other income (expense)		—		94,885			—			94,885
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		—		123,047			—			123,047
(Provision for) Benefit from income taxes		—		(1,827	)		—			(1,827	)
Equity in earnings (loss) of subsidiaries		121,220		—			(121,220	)		—
Net income (loss)	$	121,220	$	121,220		$	(121,220	)	$	121,220

	Year Ended December 31, 2017
	Parent Issuer			Subsidiary Guarantor			Intercompany Eliminations		Consolidated
	(in thousands)
Operating and other revenues	$	252,257		$	582		$	—	$	252,839
Operating expenses		(266,119	)		(1,420	)		—		(267,539	)
General and administrative		(42,476	)		—			—		(42,476	)
Merger transaction expense		(8,749	)		—			—		(8,749	)
Interest expense		(57,710	)		—			—		(57,710	)
Interest and other income (expense)		(15,992	)		—			—		(15,992	)
Income (loss) before income taxes and equity in earnings (loss) of subsidiaries		(138,789	)		(838	)		—		(139,627	)
(Provision for) Benefit from income taxes		1,402			—			—		1,402
Equity in earnings (loss) of subsidiaries		(838	)		—			838		—
Net income (loss)	$	(138,225	)	$	(838	)	$	838	$	(138,225	)

104

Condensed Consolidating Statements of Cash Flows

	Year Ended December 31, 2019
	Parent Guarantor		Subsidiary Issuer			Subsidiary Guarantor			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	—	$	278,622		$	13		$	—		$	278,635
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		—		(426,416	)		—			—			(426,416	)
Additions to furniture, fixtures and other		—		(4,286	)		(376	)		—			(4,662	)
Proceeds from sale of properties		—		1,334			—			—			1,334
Other investing activities		—		(1,612	)		—			—			(1,612	)
Intercompany transfers		—		(363	)		—			363			—
Cash flows from financing activities:
Proceeds from debt		—		222,000			—			—			222,000
Principal payments on debt		—		(83,859	)		—			—			(83,859	)
Proceeds from sale of common stock, net of offering costs		—		1			—			—			1
Intercompany transfers		—		—			363			(363	)		—
Other financing activities		—		(1,746	)		—			—			(1,746	)
Change in cash and cash equivalents		—		(16,325	)		—			—			(16,325	)
Beginning cash and cash equivalents		—		32,774			—			—			32,774
Ending cash and cash equivalents	$	—	$	16,449		$	—		$	—		$	16,449

	Year Ended December 31, 2018
	Parent Guarantor		Subsidiary Issuer			Intercompany Eliminations		Consolidated
	(in thousands)
Cash flows from operating activities	$	—	$	231,441		$	—	$	231,441
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		—		(453,616	)		—		(453,616	)
Additions to furniture, fixtures and other		—		(853	)		—		(853	)
Repayment of debt associated with merger, net of cash acquired		—		(53,357	)		—		(53,357	)
Proceeds from sale of properties		—		(221	)		—		(221	)
Other investing activities		—		364			—		364
Cash flows from financing activities:
Principal payments on debt		—		(469	)		—		(469	)
Proceeds from sale of common stock, net of offering costs		—		1			—		1
Other financing activities		—		(4,982	)		—		(4,982	)
Change in cash and cash equivalents		—		(281,692	)		—		(281,692	)
Beginning cash and cash equivalents		—		314,466			—		314,466
Ending cash and cash equivalents	$	—	$	32,774		$	—	$	32,774

105

	Year Ended December 31, 2017
	Parent Issuer			Subsidiary Guarantor			Intercompany Eliminations			Consolidated
	(in thousands)
Cash flows from operating activities	$	121,480		$	510		$	—		$	121,990
Cash flows from investing activities:
Additions to oil and gas properties, including acquisitions		(239,631	)		—			—			(239,631	)
Additions to furniture, fixtures and other		(926	)		—			—			(926	)
Proceeds from sale of properties		99,315			2,530			—			101,845
Other investing activities		(299	)		—			—			(299	)
Intercompany transfers		3,040			—			(3,040	)		—
Cash flows from financing activities:
Proceeds from debt		275,000			—			—			275,000
Principal payments on debt		(322,343	)		—			—			(322,343	)
Proceeds from sale of common stock, net of offering costs		110,710			—			—			110,710
Intercompany transfers		—			(3,040	)		3,040			—
Other financing activities		(7,721	)		—			—			(7,721	)
Change in cash and cash equivalents		38,625			—			—			38,625
Beginning cash and cash equivalents		275,841			—			—			275,841
Ending cash and cash equivalents	$	314,466		$	—		$	—		$	314,466

16. Subsequent Event

Reverse Stock Split. On October 20, 2020, the Company announced a reverse stock split of the Company’s outstanding

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

The reverse stock split was effected to increase the per share trading price of the Company’s common stock to satisfy the $1.00 minimum closing price requirement for continued listing on the NYSE. As a result of the reverse stock split, every 50 pre-split shares of common stock outstanding were automatically combined into one issued and outstanding share of common stock. The fractional shares that resulted from the reverse stock split were canceled and paid out in cash. The reverse stock split reduced the number of shares of the Company’s outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares. The total number of shares of common stock that the Company is authorized to issue was reduced from 400,000,000 to 8,000,000 shares.

All share and per share amounts were retroactively adjusted for all periods presented to give effect to this reverse stock split, including reclassifying an amount equal to the reduction in par value of the Company’s common stock to additional paid-in capital.

106

SUPPLEMENTAL INFORMATION TO CONSOLIDATED FINANCIAL STATEMENTS

(In Thousands, Except Per Share Data Unless Otherwise Indicated)

(Unaudited)

Oil and Gas Producing Activities

Costs Incurred. Costs incurred in oil and gas property acquisition, exploration and development activities and related depletion per equivalent units-of-production were as follows:

	Year Ended December 31,
	2019		2018		2017
	(in thousands, except per Boe data)
Acquisition costs:
Unproved properties	$	2,784	$	623,798	$	17,875
Proved properties		1,575		108,323		2,458
Exploration costs		113		70		80
Development costs		351,545		491,226		239,236
Asset retirement obligation		3,812		12,759		11,577
Total costs incurred (1)	$	359,829	$	1,236,176	$	271,226
Depletion per Boe of production	$	25.62	$	22.46	$	22.85

(1) Total costs incurred for the year ended December 31, 2018, includes $722.6 million related to the proved and unproved oil and gas properties and asset retirement obligations acquired in the Merger.

Supplemental Oil and Gas Reserve Information. The reserve information presented below is based on estimates of net proved reserves as of December 31, 2019, 2018 and 2017 that were prepared by internal petroleum engineers in accordance with guidelines established by the SEC and were audited by the Company’s independent petroleum engineering firm NSAI in 2019, 2018 and 2017.

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and NGLs which geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs under existing economic and operating conditions (i.e., prices and costs as of the date the estimate is made). Proved developed oil and gas reserves are reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

107

Analysis of Changes in Proved Reserves. The following table sets forth information regarding the Company’s estimated net total proved and proved developed oil and gas reserve quantities:

	Oil (MBbls)			Gas (MMcf)			NGLs (MBbls)			Equivalent Units (MBoe)
Proved reserves:
Balance at December 31, 2016		31,010			76,203			11,142			54,853
Purchases of oil and gas reserves in place		1,891			7,865			1,244			4,446
Extension, discoveries and other additions		18,125			54,995			8,599			35,890
Revisions of previous estimates		2,990			17,710			2,855			8,797
Sales of reserves		(10,196	)		(4,902	)		(187	)		(11,200	)
Production		(4,203	)		(8,952	)		(1,307	)		(7,002	)
Balance at December 31, 2017		39,617			142,919			22,346			85,784
Purchases of oil and gas reserves in place		6,891			11,549			2,351			11,167
Extension, discoveries and other additions		31,231			44,712			7,649			46,332
Revisions of previous estimates		(12,417	)		(46,024	)		(8,425	)		(28,513	)
Sales of reserves		(16	)		(17	)		(2	)		(21	)
Production		(6,330	)		(12,864	)		(1,697	)		(10,171	)
Balance at December 31, 2018		58,976			140,275			22,222			104,578
Purchases of oil and gas reserves in place		1,226			2,123			343			1,923
Extension, discoveries and other additions		20,847			51,924			6,623			36,124
Revisions of previous estimates		738			3,923			(3,909	)		(2,517	)
Sales of reserves		(25	)		(330	)		(50	)		(130	)
Production		(7,668	)		(16,614	)		(2,101	)		(12,538	)
Balance at December 31, 2019		74,094			181,301			23,128			127,440
Proved developed reserves:
December 31, 2017		17,392			74,527			11,652			41,465
December 31, 2018		24,468			84,022			12,910			51,382
December 31, 2019		25,651			89,356			11,243			51,787
Proved undeveloped reserves:
December 31, 2017		22,225			68,392			10,694			44,318
December 31, 2018		34,508			56,253			9,312			53,197
December 31, 2019		48,443			91,945			11,885			75,653

At December 31, 2019, the Company’s proved reserves increased as a result of extensions, discoveries and other additions in the amount of 36.1 MMBoe and from the purchase of oil and gas reserves in place of 1.9 MMboe. The increase in proved reserves was offset by revisions of previous estimates of 2.5 MMboe primarily as a result of lower NGL yields. In addition, proved reserves declined 12.5 MMboe due to 2019 production.

At December 31, 2018, the Company’s proved reserves increased as a result of extensions, discoveries and other additions in the amount of 46.3 MMBoe and from the purchase of oil and gas reserves in place of 11.2 MMboe. The increase in proved reserves was offset by revisions of previous estimates of 28.5 MMboe and a decline related to 2018 production of 10.2 MMboe.

At December 31, 2017, the Company’s proved reserves increased by 8.8 MMBoe due to positive revisions of previous estimates and by 35.9 MMBoe through extensions, discoveries and other additions. These increases to proved reserves were the result of the 2017 drilling activity and the timing of development with 2 drilling rigs. The increase in proved reserves was offset by the sale of the Company’s non-core assets in the Uinta Basin.

108

The analysis of changes in proved reserves outlined above includes both proved developed and proved undeveloped reserve quantities. The following table illustrates the change in the Company’s proved undeveloped reserves:

	As of December 31,
Proved Undeveloped Reserves:	2019			2018			2017
	(MMBoe)
Beginning balance		53.2			44.3			18.5
Additions from drilling program (1)(2)		32.2			41.3			31.7
Acquisitions		1.9			5.2			—
Engineering revisions (3)		0.8			(6.7	)		10.8
Price revisions		(0.4	)		0.2			0.2
Converted to proved developed		(12.1	)		(21.1	)		(13.0	)
Sold/ expired/ other (4)		—			(10.0	)		(3.9	)
Total proved undeveloped reserves (5)		75.6			53.2			44.3

(1) The increase in proved undeveloped reserves for the year ended December 31, 2019 was related to the expansion of our drilling program in the Hereford field and a successful extension test in our Northeast Wattenberg field.

(2) The increase in proved undeveloped reserves for the year ended December 31, 2018 was primarily related to the addition of the Hereford field as a result of the Merger with Fifth Creek. The upward revisions include 41.0 MMboe related to the Hereford field that were added to the proved undeveloped reserve category as these locations are included in our near-term development plans.

(3) Negative engineering revisions for the year ended December 31, 2018 of 6.7 MMBOE are composed of 2.9 MMBoe at Hereford due to results from nine drilled but not completed (“DUC”) wells acquired in the Merger which were testing tighter well spacing, and two of which experienced mechanical issues, and 3.8 MMBoe at Northeast Wattenberg due to well under performance in a new development.

(4) For the year ended December 31, 2018, 10.0 MMboe of proved undeveloped reserves in our Northeast Wattenberg field were removed due to the Merger as a result of focusing our drilling plans to target the higher return locations in the Hereford field.

(5) Our proved undeveloped locations as of December 31, 2019 represent approximately 7 rig-years of drilling inventory which we currently plan to develop over the next 2 to 3 years. This proved undeveloped inventory represents a conservative investment decision to drill these locations within the five-year development window allowed at the time the applicable proved undeveloped reserve is booked and is only a small portion of our large resource base, much of which meets the engineering definition for proved undeveloped reserves. However, the timing of such drilling is subject to change based on a number of factors, many of which are unpredictable and beyond our control, such as changes in commodity prices, anticipated cash flows and projected rate of return, access to capital, new opportunities with better returns on investment that were not known at the time of the reserve report, asset acquisitions and/or sales and actions or inactions of other co-owners or industry operators. As such, the relative proportion of total proved undeveloped locations that we develop may not necessarily be uniform from year to year, but could vary by year based upon the foregoing factors. We attempt to maximize the rate of return on capital deployed, which requires that we continually review all investment options available. As a result, at times we may delay or remove the drilling of certain projects, including scheduled proved undeveloped locations, in favor of projects with more attractive rates of return, leading us to deviate from our original development plan.

Standardized Measure. Certain information concerning the assumptions used in computing the valuation of proved reserves and their inherent limitations are discussed below. The Company believes such information is important for a proper understanding and assessment of the data presented.

For the years ended December 31, 2019, 2018 and 2017, future cash inflows are calculated by applying the 12-month average pricing (as is required by the rules of the SEC) of oil and gas relating to the Company’s proved reserves to the year-end

109

quantities of those reserves. For the year ended December 31, 2019, calculations were made using adjusted average prices of $52.01 per Bbl for oil, $17.84 per Bbl for NGLs and $0.60 per Mcf for gas, as compared to the average benchmark prices of $55.85 per Bbl for oil, a percentage of the benchmark oil price per Bbl for NGLs and $2.58 per MMBtu for gas. For the year ended December 31, 2018, calculations were made using adjusted average prices of $62.99 per Bbl for oil, $25.01 per Bbl for NGLs and $1.23 per Mcf for gas, as compared to the average benchmark prices of $65.56 per Bbl for oil, $32.71 per Bbl for NGLs and $3.10 per MMBtu for gas. For the year ended December 31, 2017, calculations were made using adjusted average prices of $48.87 per Bbl for oil, $17.21 per Bbl for NGLs and $2.29 per Mcf for gas, as compared to the average benchmark prices of $51.34 per Bbl for oil, $27.40 per Bbl for NGLs and $2.98 per MMBtu for gas. The differences between the average benchmark prices and the adjusted average prices used in the calculation of the standardized measure are attributable to adjustments made for transportation, quality and basis differentials. The Company also records an overhead charge against its future cash flows.

The assumptions used to calculate estimated future cash inflows do not necessarily reflect the Company’s expectations of actual revenues or costs, nor their present worth. In addition, variations from the expected production rate also could result directly or indirectly from factors outside of the Company’s control, such as unexpected delays in development, changes in prices or regulatory or environmental policies. The reserve valuation further assumes that all reserves will be disposed of by production. However, if reserves are sold in place, additional economic considerations could also affect the amount of cash eventually realized.

Future development and production costs are calculated by estimating the expenditures to be incurred in developing and producing the proved oil, gas and NGL reserves at the end of the year, based on year-end costs and assuming continuation of existing economic conditions.

Future income tax expenses are calculated by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax net cash flows relating to the Company’s proved oil, gas and NGL reserves. Permanent differences in oil and gas related tax credits and allowances are recognized.

The following table presents the standardized measure of discounted future net cash flows related to proved oil, gas and NGL reserves:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Future cash inflows	$	4,375,428		$	4,442,618		$	2,647,413
Future production costs		(1,313,032	)		(1,178,350	)		(718,752	)
Future development costs		(1,219,452	)		(877,752	)		(431,723	)
Future income taxes		(78,426	)		(229,405	)		—
Future net cash flows		1,764,518			2,157,111			1,496,938
10% annual discount		(790,648	)		(881,110	)		(667,627	)
Standardized measure of discounted future net cash flows	$	973,870		$	1,276,001		$	829,311

The “standardized measure” is the present value of estimated future cash inflows from proved oil, gas and NGL reserves, less future development and production costs and future income tax expenses, using prices and costs as of the date of estimation without future escalation, without giving effect to hedging activities, non-property related expenses such as general and administrative expenses, debt service and depreciation, depletion and amortization and discounted using an annual discount rate of 10% to reflect timing of future cash flows.

The present value (at a 10% annual discount) of future net cash flows from the Company’s proved reserves is not necessarily the same as the current market value of its estimated oil, gas and NGL reserves. The Company bases the estimated discounted future net cash flows from its proved reserves on prices and costs in effect on the day of estimate in accordance with the applicable accounting guidance. However, actual future net cash flows from its oil, gas and NGL properties will also be affected by factors such as actual prices the Company receives for oil, gas and NGLs, the amount and timing of actual production, supply of and demand for oil and natural gas and changes in governmental regulations or taxation.

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The timing of both the Company’s production and incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing of actual future net cash flows from proved reserves, and thus their actual present value. In addition, the 10% annual discount factor the Company uses when calculating discounted future net cash flows may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with the Company or the oil and natural gas industry in general.

A summary of changes in the standardized measure of discounted future net cash flows is as follows:

	Year Ended December 31,
	2019			2018			2017
	(in thousands)
Standardized measure of discounted future net cash flows, beginning of period	$	1,276,001		$	829,311		$	329,309
Sales of oil and gas, net of production costs and taxes		(362,320	)		(365,472	)		(191,669	)
Extensions, discoveries and improved recovery, less related costs		177,002			533,829			346,973
Quantity revisions		(73,427	)		(535,618	)		112,452
Price revisions		(450,944	)		479,129			253,738
Previously estimated development costs incurred during the period		213,841			124,932			138,094
Changes in estimated future development costs		(23,976	)		67,645			(118,967	)
Accretion of discount		130,346			80,234			31,816
Purchases of reserves in place		15,055			145,010			42,979
Sales of reserves		(984	)		—			(107,620	)
Changes in production rates (timing) and other		(8,689	)		(1,034	)		(7,794	)
Net changes in future income taxes		81,965			(81,965	)		—
Standardized measure of discounted future net cash flows, end of period	$	973,870		$	1,276,001		$	829,311

Quarterly Financial Data

The following is a summary of the unaudited quarterly financial data, including income (loss) before income taxes, net income (loss) and net income (loss) per common share for the years ended December 31, 2019 and 2018.

	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share data)
Year Ended December 31, 2019
Total revenues	$	101,980		$	107,584		$	121,281		$	121,814
Less: Costs and expenses		109,364			114,701			121,812			127,466
Operating income (loss)	$	(7,384	)	$	(7,117	)	$	(531	)	$	(5,652	)
Income (loss) before income taxes		(125,940	)		(1,800	)		15,444			(64,650	)
Net income (loss)		(96,229	)		(1,910	)		11,114			(47,805	)
Net income (loss) per common share, basic (1)		(22.92	)		(0.45	)		2.64			(11.34	)
Net income (loss) per common share, diluted (1)		(22.92	)		(0.45	)		2.63			(11.34	)

(1) All per share amounts were retroactively adjusted for all periods presented to give effect to the 1-for-50 reverse stock split effective October 30, 2020. See Note 16 to the Consolidated Financial Statements for additional information.

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	First Quarter			Second Quarter			Third Quarter			Fourth Quarter
	(in thousands, except per share data)
Year Ended December 31, 2018
Total revenues	$	80,810		$	110,398		$	131,126		$	130,683
Less: Costs and expenses		73,015			88,626			95,968			114,543
Operating income (loss)	$	7,795		$	21,772		$	35,158		$	16,140
Income (loss) before income taxes		(24,937	)		(46,906	)		(29,360	)		224,250
Net income (loss)		(24,937	)		(46,906	)		(29,360	)		222,423
Net income (loss) per common share, basic (1)		(10.09	)		(11.20	)		(7.01	)		53.08
Net income (loss) per common share, diluted (1)		(10.09	)		(11.20	)		(7.01	)		53.05

(1) All per share amounts were retroactively adjusted for all periods presented to give effect to the 1-for-50 reverse stock split effective October 30, 2020. See Note 16 to the Consolidated Financial Statements for additional information.

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