EDGAR 10-K Filing

Company CIK: 1725526
Filing Year: 2021
Filename: 1725526_10-K_2021_0001725526-21-000016.json

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ITEM 1. BUSINESS
Items 1 and 2. Business and Properties.
BUSINESS
General
HighPoint Resources Corporation, a Delaware corporation, together with its wholly-owned subsidiaries (collectively, the “Company”, “HighPoint”, “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 “2018 Merger Agreement”), pursuant to which Bill Barrett combined with Fifth Creek Energy Operating Company, LLC (“Fifth Creek”) (the “2018 Merger”). As a result of the 2018 Merger, Bill Barrett became a wholly-owned subsidiary of HighPoint Resources Corporation and subsequently Bill Barrett changed its name to HighPoint Operating Corporation. 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 2018 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 17th 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.
Significant Business Developments
Pending Merger with Bonanza Creek Energy, Inc.
On November 9, 2020, the Company and Bonanza Creek Energy, Inc., a Delaware corporation (“Bonanza Creek”), entered into a definitive merger agreement (“Merger Agreement”) to effectuate the strategic combination of Bonanza Creek and HighPoint (“Merger”). The transaction has been unanimously approved by the board of directors of each company. Under the terms of the Merger Agreement, Bonanza Creek has commenced a registered offer to exchange HighPoint’s senior unsecured notes (the “HighPoint Notes”) for senior notes and common stock of Bonanza Creek (the “Exchange Offer”). The Exchange Offer is conditioned on a minimum participation condition of not less than 97.5% of the aggregate outstanding principal amount of each series of HighPoint Notes being validly tendered in accordance with the terms of the Exchange Offer prior to the expiration date of the Exchange Offer (the “Minimum Participation Condition”). Based on the number of shares of Bonanza Creek common stock outstanding as of the date of the Merger Agreement, existing holders of Bonanza Creek common stock
will own approximately 68% of the issued and outstanding shares of the combined company, existing holders of HighPoint common stock will own approximately 1.6% of the combined company and holders of the HighPoint Notes will own approximately 30.4% of the combined company and up to $100 million of senior unsecured notes to be issued by Bonanza Creek in connection with the Exchange Offer. Registration statements on Form S-4 of Bonanza Creek and a merger proxy of HighPoint have been declared effective by the SEC. The Exchange Offer expires on March 11, 2021 (unless extended by HighPoint and Bonanza Creek) and special meetings for Bonanza Creek and HighPoint stockholders will both be held on March 12, 2021 to approve the Merger.
Concurrently with the Exchange Offer, HighPoint is soliciting votes from the holders of the HighPoint Senior Notes to accept or reject a prepackaged plan of reorganization under Chapter 11 of the United States Bankruptcy Code in the United States Bankruptcy Court for the District of Delaware (the “Court,” and such plan, the “Prepackaged Plan”).
If the Minimum Participation Condition is met, and if certain customary closing conditions are satisfied (including approval by each company’s shareholders), the companies will effect the Exchange Offer and Bonanza Creek will acquire HighPoint at closing through a merger outside of bankruptcy, whereby HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. If the Minimum Participation Condition is not met, HighPoint intends to file voluntary petitions under Chapter 11 with the Court to effectuate the solicited Prepackaged Plan and consummate the transaction. The consummation of the Prepackaged Plan will be subject to confirmation by the Court in addition to other conditions set forth in the Prepackaged Plan, a transaction support agreement and related transaction documents.
The transactions are expected to close in the first quarter of 2021 under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. There can be no assurance that the Merger will be consummated or consummated within the expected timeframe.
PROPERTIES
Overview
As of December 31, 2020, 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.
DJ Basin Key Statistics
•Estimated proved developed reserves as of December 31, 2020 - 50.8 MMBoe.
•Producing wells - We had interests in 566 gross (396.5 net) producing wells as of December 31, 2020, and we serve as operator of 451 gross wells.
•2020 net production - 10,953 MBoe.
•Acreage - We held 54,722 net undeveloped and 76,961 net developed acres as of December 31, 2020.
•Capital expenditures - Our capital expenditures for 2020 were $97.3 million for participation in the drilling of 31 gross (13.7 net) wells, acquisition of leasehold acres and construction of gathering facilities.
•As of December 31, 2020, we were not drilling any wells, but were waiting to complete 39 gross (16.0 net) wells.
•Based on our proved reserves as of January 1, 2021, we have a 66% weighted average working interest in our producing wells in the DJ Basin.
The DJ Basin is an oil development area where operators are targeting the Niobrara and Codell formations and employing new technologies to optimize oil recoveries and economic returns. The DJ Basin has a low cost structure, mature infrastructure, strong production efficiencies, multiple producing horizons, multiple service providers, established reserves, and prospective drilling opportunities, which helps facilitate predictable production and reserve growth.
The DJ Basin is our core area of operation; we drilled 31 gross (13.7 net) operated wells and placed 34 gross (25.0 net) operated wells on initial flowback in 2020. We had two rigs operating until we suspended drilling in May of 2020. Prior to suspending drilling and completion operations, we continued to drill extended reach horizontal wells in the Niobrara and Codell formations across the DJ Basin, continuing to optimize our completion technology.
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, 2020, 2019 and 2018 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 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, 2020, 2019 and 2018. 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 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)
2020 2019 2018
Proved Developed Reserves:
Oil (MMBbls) 22.6 25.7 24.5
Natural gas (Bcf) 92.6 89.4 84.0
NGLs (MMBbls) 12.8 11.2 12.9
Total proved developed reserves (MMBoe) 50.8 51.8 51.4
Proved Undeveloped Reserves:
Oil (MMBbls) - 48.4 34.5
Natural gas (Bcf) - 91.9 56.3
NGLs (MMBbls) - 11.9 9.3
Total proved undeveloped reserves (MMBoe) (2)
- 75.6 53.2
Total Proved Reserves (MMBoe) 50.8 127.4 104.6
(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 2020 for natural gas (Henry Hub price) and oil (WTI Cushing price), subject to certain adjustments, or $1.99 per MMBtu of natural gas and $39.54 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 51% and 52% of our estimated proved reserves (by volume) were undeveloped for the years ended December 31, 2019 and 2018, respectively.
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”.
Annually, management develops a capital expenditure plan based on the best data available at the time. Our capital expenditure plan incorporates a development plan for converting PUD reserves to proved developed and includes only PUD reserves that we are reasonably certain will be drilled within five years of booking based upon management’s evaluation of a number of qualitative and quantitative factors, including estimated risk-based returns; estimated well density; commodity prices and cost forecasts; recent drilling recompletion or re-stimulation results and well performance; and anticipated availability of services, equipment, supplies and personnel. This process is intended to ensure that PUD reserves are only booked for locations where a final investment decision has been made based on current corporate strategy. In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19. As the virus spread, global economic activity began to slow resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL
prices on the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. In response to these conditions, we indefinitely suspended our drilling and completion activity starting in May 2020. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, and that agreement restricts our near-term capital spending levels and does not allow for drilling or completion operations. Furthermore, if the Merger does not close as contemplated, we do not have assurance that we will have the capital availability to resume drilling and completion operations. As a result, we have reclassified 65.9 MMboe of PUD reserves to non-proved categories as of December 31, 2020, not because the PUD locations are uneconomic but rather because we may not have the adequate financial capability to develop the PUD reserves within the five year development window.
The following tables illustrate the history of our proved undeveloped reserves from December 31, 2018 through December 31, 2020:
As of December 31,
Proved Undeveloped Reserves: 2020 2019 2018
(MMBoe)
Beginning balance 75.6 53.2 44.3
Additions from drilling program (1)(2)
- 32.2 41.3
Acquisitions - 1.9 5.2
Engineering revisions (3)
(4.0) 0.8 (6.7)
Price revisions (0.2) (0.4) 0.2
Converted to proved developed (5.5) (12.1) (21.1)
Sold/ expired/ other (4)(5)
(65.9) - (10.0)
Total proved undeveloped reserves - 75.6 53.2
(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 2018 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 2018 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, 2020 proved undeveloped reserves of 65.9 MMboe were removed based on the information described above.
(5)For the year ended December 31, 2018, 10.0 MMboe of proved undeveloped reserves in our Northeast Wattenberg field were removed due to the 2018 Merger as a result of focusing our drilling plans to target the higher return locations in the Hereford field.
Year Ended December 31,
2020 2019 2018
Proved undeveloped locations converted to proved developed wells during year
31 64 69
Proved undeveloped drilling and completion capital invested (in millions)
$ 77.2 $ 262.4 $ 269.1
Proved undeveloped facilities capital invested (in millions) $ 2.8 $ 13.5 $ 28.5
Percentage of proved undeveloped reserves converted to proved developed
7 % 23 % 48 %
Prior year’s proved undeveloped reserves remaining undeveloped at current year end (MMBoe) - 42.4 11.2
At December 31, 2020, our proved undeveloped reserves were zero. At December 31, 2019, our proved undeveloped reserves were 75.6 MMBoe. During 2020, 5.5 MMBoe, or 7% of our December 31, 2019 proved undeveloped reserves (31 wells), were converted into proved developed reserves and required $77.2 million of drilling and completion capital and $2.8
million of facilities capital. These wells produced 2.8 MMBoe in 2020. During 2020, we reduced our proved undeveloped reserves by 65.9 MMboe due to suspending our drilling and completion programs for the foreseeable future in our core development areas. Negative engineering revisions decreased proved undeveloped reserves by 4.0 MMBoe. Negative pricing revisions decreased proved undeveloped reserves by 0.2 MMBoe.
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 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.
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.
•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.. 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.
•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 2020 and 2019, we paid NSAI approximately $110,000 and $245,000, respectively, for auditing our reserves estimates.
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,
2020 2019 2018
Company Production Data:
Oil (MBbls) 5,909 7,668 6,330
Natural gas (MMcf) 16,428 16,614 12,864
NGLs (MBbls) 2,352 2,101 1,697
Combined volumes (MBoe) 10,999 12,538 10,171
Daily combined volumes (Boe/d) 30,052 34,351 27,866
DJ Basin - Production Data (1):
Oil (MBbls) 5,879 7,668 6,330
Natural gas (MMcf) 16,374 16,614 12,864
NGLs (MBbls) 2,345 2,101 1,697
Combined volumes (MBoe) 10,953 12,538 10,171
Daily combined volumes (Boe/d) 29,926 34,351 27,866
Average Realized Prices before Hedging:
Oil (per Bbl) $ 34.62 $ 52.86 $ 62.04
Natural gas (per Mcf) 1.33 1.56 1.75
NGLs (per Bbl) 9.69 10.00 22.18
Combined (per Boe) 22.66 36.07 44.53
Average Realized Prices with Hedging:
Oil (per Bbl) $ 53.25 $ 54.39 $ 54.51
Natural gas (per Mcf) 1.30 1.50 1.76
NGLs (per Bbl) 9.69 10.00 22.18
Combined (per Boe) 32.62 36.92 39.85
Average Costs ($ per Boe):
Lease operating expense $ 2.96 $ 3.01 $ 2.74
Gathering, transportation and processing expense 1.68 0.85 0.46
Total production costs excluding production taxes
$ 4.64 $ 3.86 $ 3.20
Production tax expense (2)
(0.06) 1.88 3.61
Depreciation, depletion and amortization 13.55 25.62 22.46
General and administrative (3)
3.92 3.57 4.44
(1)The DJ Basin was the only development area that contained 15% or more of our total proved reserves as of December 31, 2020, 2019 and 2018.
(2)Production taxes for the year ended December 31, 2020 included reductions of $7.3 million and $5.4 million, respectively, associated with a true-up to actual 2018 Colorado ad valorem taxes and an adjustment to estimated 2019 Colorado ad valorem taxes to be paid in 2021 as a result of refunds and new information received in 2020. In addition, production taxes were reduced by $1.5 million associated with a true up to 2019 Colorado severance taxes as a result of refunds received and by $1.8 million to account for Colorado severance tax refunds based on an audit of tax years 2015 to 2017. Excluding these adjustments, production taxes would have been $1.48 per Boe.
(3)Included in general and administrative expense is long-term cash and equity incentive compensation of $3.5 million (or $0.32 per Boe), $8.6 million (or $0.69 per Boe) and $7.2 million (or $0.71 per Boe) for the years ended December 31, 2020, 2019 and 2018, respectively.
Productive Wells
The following table sets forth information at December 31, 2020 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 558.0 389.4 8.0 7.1
Other 4.0 0.3 4.0 1.2
Total 562.0 389.7 12.0 8.3
Developed and Undeveloped Acreage
The following table sets forth information as of December 31, 2020 relating to our leasehold acreage.
Developed Acreage Undeveloped Acreage
Basin/Area Gross Net Gross Net
DJ 93,441 76,961 80,133 54,722
Other (1)
4,922 2,093 112,492 51,412
Total 98,363 79,054 192,625 106,134
(1)Other includes 45,188 net undeveloped acres in the Paradox Basin.
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, 2020, 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 2021 2022 2023 2024 Thereafter (1)
Total
DJ 14,537 7,091 5,489 19 27,586 54,722
Other - - 288 - 51,124 51,412
Total 14,537 7,091 5,777 19 78,710 106,134
(1)Thereafter includes 11,178 acres in the DJ and 45,922 acres in other that are held by production.
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,
2020 2019 2018
Gross Net Gross Net Gross Net
Development
Productive 34.0 25.0 106.0 67.2 95.0 76.1
Dry - - - - - -
Exploratory
Productive - - - - - -
Dry - - - - - -
Total
Productive 34.0 25.0 106.0 67.2 95.0 76.1
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 2020, four customers individually accounted for over 10% of our oil, gas and NGL production revenues. 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.
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 will 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 will 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. As of February 4, 2021, we have hedged 3,098,000 barrels and 365,000 barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively, at price levels that provide some economic certainty to our cash flows. Currently, 7 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 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 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 and proper maintenance 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. 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.
In 2018 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 2020, have imposed 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 and the siting of new wells. The majority of these regulations were approved late in 2020 and became effective on January 15, 2021, and the COGCC is still in the process of issuing guidance and direction on implementation of the new regulations. 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. Additionally, our staff were extensively involved in the rulemaking process throughout 2020 and we believe that we have been able to effectively evaluate the new requirements and implement the measures necessary to maintain compliance with the new regulations.
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. The public comment period on the notice for proposed rulemaking ended on March 10, 2020. The final revisions to the NEPA regulations were published on July 16, 2020 with an effective date of September 14, 2020. Several environmental groups and states filed suit and requested a preliminary injunction to stay the implementation of the new rule. That motion was denied and the new rule went
into effect on September 14, 2020. Highlights of the new rule include presumptive limits on the amount of time required to complete the NEPA process and the number of pages needed for Environmental Assessments and Environmental Impact Statements. 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 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 implemented 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 generally regulates 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 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. The Navigable Waters Protection Rule became effective on June 22, 2020 and is being implemented by the EPA and the Corps in 49 of the 50 states. On June 19, 2020, the U.S. District Court for the District of Colorado stayed the effective date of the Navigable Waters Protection Rule in the State of Colorado, meaning the old definition remains in effect for all of our operations. 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, 2016 and 2020. 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. On August 13, 2020, the EPA issued two final rules amending the 2012 and 2016 NSPS for the oil and natural gas industry. The amendments recognize that controls used to reduce VOC emissions also reduce methane emissions and, thus, rescinded the methane standards for the production and processing segments of the oil and gas industry. Several other technical amendments were made to reduce the regulatory burden associated with multiple aspects of the NSPS, including incorporating state fugitive emissions standards for well sites and compressor stations in certain states, including Colorado. Both of the final rules are currently subject to legal challenge in U.S. Court of Appeals for the D.C. Circuit. On January 20, 2021, President Biden signed Executive Order 13990: “Protecting Public Health and the Environment and Restoring Science to Tackle the Climate Crisis.” The Executive Order established a federal policy to, among other things, reduce greenhouse gas emissions. The Executive Order directs the EPA to review certain federal regulations promulgated during the preceding 4 years that conflict with this federal policy, including the two final rules amending the 2012 and 2016 NSPS, discussed above. The Executive Order also directed the EPA to consider proposing new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments, by September 2021.
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 filed challenges to the 2018 rule in the United States District Court for the Northern District of California. On July 15, 2020, the court ruled in favor of plaintiffs and ordered that the 2018 Revision Rule be vacated. On July 21, 2020, the U.S.
District Court for the District of Wyoming lifted the stay in the case challenging the 2016 Waste Prevention Rule. On October 8, 2020, the court found that the BLM exceeded its statutory authority and acted arbitrarily in promulgating the 2016 Waste Prevention Rule. The court ordered that the rule be vacated, except for certain severable provisions pertaining to royalty-free use of production and royalty rates on competitive leases. The effect of the court’s order is to vacate all provisions of the Waste Prevention Rule pertaining to the loss of gas through venting, flaring, and leaks, and to reinstate BLM Notice to Lessees NTL-4A with respect to venting, flaring, and avoidably/unavoidably lost determinations.
The EPA already requires reporting of greenhouse gases, such as CO2 and methane, from operations. In 2014, 2017, 2019 and 2020, Colorado expanded its oil and gas air regulations, including the adoption of a new state-level emission inventory requirement for oil and gas operations that includes reporting of greenhouse gases. Additional oil and gas-related air quality rulemakings are scheduled for February and December of 2021. In 2019, the Colorado legislature passed House Bill 19-1261 which directs Colorado to reduce greenhouse gas emissions 26% by 2025, 50% by 2030 and 90% by 2050 from 2005 levels. We anticipate that the oil and gas industry will be significantly targeted in these efforts to reduce greenhouse gas emissions in the State of Colorado. 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. Effective January 27, 2020, the Denver Metro/North Front Range NAA was reclassified again to from “moderate” to “serious”. The “serious” classification triggered 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 as new rules are promulgated to meet these new requirements. Based on current air quality monitoring data, it is expected that the Denver Metro/North Front Range NAA will be further reclassified to “severe” status in 2021 or 2022. This will trigger additional obligations for the state under the CAA and could result in new and more stringent air quality control requirements, which may in turn result in significant costs, and delays in obtaining necessary permits applicable to our operations. 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 conducted oil and gas-related air quality rulemakings in 2020 related to the control of emissions from natural gas-fired reciprocating internal combustion engines, oil and gas flowback tanks, and ambient monitoring of emissions at oil and gas facilities that go through pre-production operations. Additional future rulemaking will include discussion of continuous emissions monitoring equipment at oil and gas facilities, use of natural gas-driven pneumatic controllers and oil and gas-related greenhouse gas emissions.
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. A federal district court in California granted BLM’s motion for summary judgement in March 2020, upholding the agency’s decision to rescind the Hydraulic Fracturing Rule. The plaintiffs in that case have appealed the California federal court’s decision to the U.S. Court of Appeals for the Ninth Circuit, where the case is pending.
On January 20, 2021, the Acting Secretary of the Interior issued an order suspending for 60 days the authority of bureaus within the Department of the Interior to issue fossil fuel authorizations, including new oil and gas leases and drilling permits on federal lands and in offshore waters. Additionally, on January 27, 2021, President Biden signed an executive order pausing leasing on federal lands and in offshore waters pending completion of a comprehensive review and reconsideration of federal oil and gas permitting and leasing practices. The executive order does not specify a timeframe by which this review must be completed. The executive order and its implementation are currently being challenged in the United States District Court for the District of Wyoming.
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. In the wake of Senate Bill 19-181 several local jurisdictions established temporary moratoriums, citing a need for the rules required by Senate Bill 19-181 to be enacted. It remains unclear whether local governments will attempt to use this new authority to more permanently restrict hydraulic fracturing or oil and gas development or whether such action would be lawful under SB 19-181 and Colorado Supreme Court precedent.
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. On January 19, 2021 the United States Court of Appeals for the District of Columbia Circuit vacated the ACE rule and remanded to the EPA to consider a new regulatory framework to replace the rule. 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 began a 12 month process to formally withdraw on November 4, 2020. On January 20, 2021, President Biden signed an executive order recommitting the United States to the Paris Agreement. 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, internal vulnerability testing, Supervisory Control and Data Acquisition (“SCADA”) protection and other security technology upgrades. We utilize a comprehensive software package to track and document our cybersecurity initiatives which are reviewed regularly by the Executive Committee and annually by the Board. Our cybersecurity initiatives are an 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 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, 2021, we had 124 employees of whom 71 work in our Denver office and 53 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.
Offices
As of December 31, 2020, we have 79,279 square feet of leased office space for our principal office in Denver, Colorado at 555 17th Street, which expires in April 2028. We also have 15,160 square feet of remaining leased office space in Greenwood Village, Colorado, which was acquired in the 2018 Merger and 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 April 30, 2020 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.

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ITEM 1A. RISK FACTORS
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 Merger and the Prepackaged Plan
The Merger may not be completed and, if it is completed, will subject our stockholders to certain risks and uncertainties. We are also subject to numerous risks associated with the Prepackaged Plan.
Key risks associated with the Merger and the Prepackaged Plan are described below, and are discussed in the “Risk Factors” section of Bonanza Creek’s Registration Statement on Form S-4 filed with the SEC in connection with the Merger:
•Because the market price of Bonanza Creek common stock will fluctuate, HighPoint stockholders and holders of HighPoint equity awards cannot be sure of the value of the shares of Bonanza Creek common stock they will receive, in the aggregate, in the Merger. In addition, because the number of shares of Bonanza Creek common stock to be issued in the Merger is fixed, the number of shares of Bonanza Creek common stock to be received, in the aggregate, by HighPoint stockholders and holders of HighPoint equity awards in the Merger will not change between now and the time the Merger is completed to reflect changes in the trading prices of Bonanza Creek common stock or HighPoint common stock.
•HighPoint stockholders, as of immediately prior to the Merger, will have reduced ownership in the combined company.
•Bonanza Creek and HighPoint must obtain certain regulatory approvals and clearances to consummate the Merger, which, if delayed, not granted or granted with unacceptable conditions, could prevent, substantially delay or impair consummation of the Merger, result in additional expenditures of money and resources or reduce the anticipated benefits of the Merger.
•The Merger is subject to a number of conditions to the obligations of both Bonanza Creek and HighPoint to complete the Merger, which, if not fulfilled, or not fulfilled in a timely manner, may delay completion of the Merger or result in termination of the Merger Agreement.
•The Merger Agreement subjects HighPoint to restrictions on its business activities prior to the effective time of the Merger.
•The Merger Agreement limits HighPoint’s ability to pursue alternatives to the Merger, may discourage other companies from making a favorable alternative transaction proposal and, in specified circumstances, could require HighPoint to pay a termination fee to Bonanza Creek.
•Failure to complete the Merger out of court or in connection with the Prepackaged Plan could negatively impact HighPoint’s stock price and have a material adverse effect on its results of operations, cash flows and financial position.
•The transaction support agreement relating to the Merger may be terminated.
•Litigation relating to the merger could result in an injunction preventing the completion of the Merger and/or substantial costs to HighPoint or the combined company.
•The Prepackaged Plan may have a material adverse effect on HighPoint’s operations.
•Even if HighPoint receives all necessary acceptances and meets all other conditions precedent for the Prepackaged Plan to become effective, the HighPoint board may, for fiduciary or other reasons on behalf of HighPoint, choose not to commence the HighPoint Chapter 11 cases and the transactions, including the Merger, may not be completed.
•The Bankruptcy Court may not confirm the Prepackaged Plan or may require HighPoint to re-solicit votes with respect to the Prepackaged Plan.
•The Prepackaged Plan may be confirmed over the objection of the HighPoint stockholders.
•Even if HighPoint receives all acceptances necessary for the Prepackaged Plan to become effective, HighPoint may fail to meet all conditions precedent to effectiveness of the Prepackaged Plan.
•Other parties in interest might be permitted to propose alternative plans of reorganization that may be less favorable to certain of HighPoint’s constituencies than the Prepackaged Plan.
•HighPoint cannot predict the amount of time that it would spend in bankruptcy for the purpose of implementing the Prepackaged Plan and a lengthy bankruptcy proceeding could disrupt HighPoint’s business as well as impair the prospect for reorganization on the terms contained in the Prepackaged Plan.
•HighPoint may seek to amend, waive, modify or withdraw the Prepackaged Plan at any time prior to the confirmation of the Prepackaged Plan.
Risks Related to our Senior Notes and Credit Facility
Our potential inability to comply with the financial covenants in our Credit Facility have raised substantial doubt about our ability to continue as a going concern. We may not be able to generate enough cash flow to meet our debt obligations.
We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of December 31, 2020. This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of December 31, 2020. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.
In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a “going concern” (“going concern opinion”) in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion.
In response to these conditions, we have taken various steps to preserve our liquidity including (1) deferring drilling and completion activity starting in May 2020 for the foreseeable future, (2) continuing to focus on reducing our operating and overhead costs, and (3) continuing to manage our hedge portfolio. We could remain in compliance with the financial covenant if we (1) negotiate a waiver of the financial covenant with the lenders, (2) negotiate more flexible financial covenants, or (3) refinance the Credit Facility or senior notes. However, the availability of capital funding that would allow us to refinance the debt on acceptable terms has substantially diminished. In addition, we entered into a Merger Agreement with Bonanza Creek on November 9, 2020, pursuant to which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information. However, the Merger has not yet closed and the closing is subject to numerous conditions. See “Risks Related to the Merger” above and “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.
At December 31, 2020, we had cash and cash equivalents of $24.7 million and $140.0 million outstanding under the Credit Facility. At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under our Credit Facility. As part of our regular semi-annual redeterminations, the elected commitment amount on our Credit Facility was reduced to $300.0 million on May 21, 2020 and to $185.0 million on November 3, 2020. Our available borrowing capacity as of December 31, 2020 was $24.0 million, after taking into account $21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations.
If we do not generate enough cash flow from operations to satisfy our debt obligations, and the Merger does not close, we may have to undertake one or more alternative financing plans, such as:
•refinancing or restructuring our debt;
•filing for Chapter 11 bankruptcy;
•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;
•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.
Our customers, suppliers, vendors, employees and other third parties with whom we do business may react negatively to the substantial doubt about our ability to continue as a going concern.
It may be more difficult to enter into contractual arrangements with our customers who purchase our oil and gas production as well as with other oil and gas companies, including those that supply equipment and other resources that we will use in our business. We may not be able to establish strategic relationships, which may take the form of joint ventures with other third
parties. If our strategic relationships are not established or maintained, our business prospects may be limited, which could diminish our ability to conduct our operations.
Risks Related to the Oil and Natural Gas Industry and Our Business
The COVID-19 pandemic and recent developments in the oil and gas industry have and could continue to materially adversely affect our operations during 2021 and possibly beyond.
In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow, resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year ended December 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.
A U.S. and global economic downturn due to the COVID-19 pandemic or other global crisis could have a material adverse effect on our business and operations.
Any or all of the following may occur as a result of an economic downturn:
•The economic slowdown could lead to continued lower demand for oil and natural gas by individuals and industries, which in turn could result in continued lower prices for the oil and natural gas sold by us, lower revenues and possibly losses.
•The lenders under our 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.
•We may be unable to obtain additional debt or equity financing, which would require us to continue 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”). LIBOR will no longer be used as a reference index for determining interest rates under credit arrangements starting in 2023. 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. Our borrowing capacity was reduced from $500 million to $250 million in May 2020 and from $250 million to $185 million in November 2020. 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 further. This would further 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.
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 OPEC+ 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 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.
As described above, oil, natural gas and NGL prices declined significantly during 2020 due to OPEC+ unable to agree on cuts and the COVID-19 pandemic. 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 commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value for a significant period of time or cause us to change drilling plans and/or forego lease renewals or cause significant decreases in property market values, we may be required to take an impairment against the carrying values of our proved and/or unproved properties.
Accounting rules require that we periodically review the carrying value of our properties for possible impairment. Based on specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors such as lease expirations, changes in drilling plans and adverse drilling results, we may be required to take an impairment against the carrying value of our properties. An impairment constitutes a non-cash charge to earnings. For the year ended December 31, 2020, we recorded non-cash impairment charges of approximately $1.3 billion on proved and unproved oil and gas properties, and if market or other economic conditions deteriorate further or if oil and gas prices continue to decline, we may incur additional impairment charges, which may have a material adverse effect on our results of operations.
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.
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. One of the first actions of the new Biden Administration was to suspend the processing of federal permits, followed by a 90-day hiatus of the federal leasing program.
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. 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;
•personal injuries and death; and
•natural disasters or other adverse weather conditions.
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 Credit Facility decrease as a result of lower oil, natural gas and NGLs prices, which was the case for both semi-annual borrowing base redeterminations in 2020, 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 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 continue to have an adverse effect on our borrowing base.
Our future drilling plans were suspended in 2020 and continue to be suspended due to significant declines in commodity prices and a decrease in borrowing capacity on our Credit Facility. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, and that agreement restricts our near-term capital spending levels and does not allow for drilling or completion operations. Furthermore, if the Merger does not close as contemplated, we do not have assurance that we will have the capital availability to resume drilling and completion operations. This resulted in a reduction in our oil, natural gas and NGL reserves as of December 31, 2020 primarily due to removing all PUD reserves, as we are not reasonably certain the PUD reserves will be drilled within the five year development window at the time the applicable PUD reserve is booked. Continued delays in our development plans could lead to a possible loss of properties and additional declines in our oil, natural gas and NGLs reserves as well as our revenues and results of operations.
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 Credit Facility may be limited, which would affect our ability to fund our operations.
Our Credit Facility has commitments from 11 lenders. If credit markets become more turbulent as a result of the current 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.
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.
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 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.
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.
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.
Risks Related to Our Common Stock
The price of our common stock has been and may continue to be highly volatile, which may make it difficult for shareholders to sell our common stock when desired or at attractive prices.
The market price of our common stock is highly volatile. Adverse events could trigger a significant decline in the trading price of our common stock, including, among others, unfavorable changes in commodity prices or commodity price expectations, adverse regulatory developments and adverse developments relating to the Merger. Furthermore, general market conditions, including the level of, and fluctuations in, the trading prices of equity securities generally could affect the price of our stock. The stock markets frequently experience price and volume volatility that affects many companies’ stock prices, often in ways unrelated to the operating performance of those companies. In addition, the trading price of our common stock may be increased at times by market phenomena such as significant increases in retail investor interest and purchases to cover short positions. If so, those market phenomena could reverse themselves at any time, leading to a rapid and substantial decline in the price of our stock.
If we cannot meet the financial compliance standards for continued listing on the New York Stock Exchange (the “NYSE”), the NYSE may delist our common stock, which could have an adverse impact on the trading volume, liquidity and market price of our common stock.
A delisting of our common stock from the NYSE could negatively impact us because it could reduce the liquidity and market price of our common stock and reduce the number of investors willing to hold or acquire our common stock, which could negatively impact our ability to raise equity financing, and/or diminish the value of equity incentives available to provide
to our employees. The NYSE Listed Company Manual has a set of financial compliance standards we must meet to avoid being delisted from the NYSE. The financial compliance standards are defined below:
•average market capitalization of not less than $50 million over a 30 trading day period and stockholders’ equity of not less than $50 million;
•average closing share price of $1.00 over a 30 trading day period; and
•average market capitalization of not less than $15 million over a 30 day trading period, which is a minimum threshold for continued listing with no cure period.
On March 10, 2020, we were notified by the NYSE that the average closing price of our common stock over the prior 30- consecutive trading day period was below $1.00. On October 30, 2020, we completed a 1-for-50 reverse stock split of our common stock to satisfy this requirement. The reverse stock split reduced the number of shares of our outstanding common stock from 215,255,925 shares as of October 30, 2020 to 4,305,119 shares, subject to adjustment of the rounding of fractional shares.
On November 4, 2020, we were notified by the NYSE that our average market capitalization was less than $50 million over the prior 30-consecutive trading day period along with a stockholders’ equity balance of less than $50 million. As set forth in the notice, as of November 3, 2020, our prior 30-consecutive trading day average market capitalization was $42.5 million and our last reported shareholders’ equity as of June 30, 2020 was $2.2 million. In accordance with NYSE listing requirements, we submitted a plan on December 18, 2020 advising the NYSE of definitive action we have taken, or are taking, to bring us into conformity within 18 months of November 4, 2020. On January 28, 2021, the NYSE accepted our plan allowing our common stock to continue to be listed and traded on the NYSE during the cure period, subject to our compliance with the plan and other continued listing standards. The NYSE will review our compliance with the plan on a quarterly basis. If we fail to comply with the plan or do not meet continued listing standards at the end of the 18-month cure period, we will be subject to the prompt initiation of NYSE suspension and delisting procedures. Further, if our average market capitalization goes below $15 million over a 30-consecutive trading day period, there is no cure period for continued listing on the NYSE.
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.
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 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.
Our future utilization of NOLs and tax credit carryforwards have been limited by the 2018 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 2018 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 $274.7 million and $13.1 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.
Our future utilization of NOLs and tax credit carryforwards may be further limited in the event of any future ownership changes, including the pending Merger with Bonanza Creek.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
Item 1B. Unresolved Staff Comments.
Not applicable.

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ITEM 2. PROPERTIES

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ITEM 3. LEGAL PROCEEDINGS
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, other than the following.
Sterling Energy Investments LLC v. HighPoint Operating Corporation, 2020CV32034, District Court in Denver, Colorado. On June 15, 2020, Sterling Energy Investments LLC (“Sterling”) filed a complaint against HighPoint Operating Corporation, a subsidiary of ours, for breach of contract related to a Gas Purchase Agreement dated effective November 1, 2017, by and between HighPoint Operating Corporation and Sterling. Sterling alleges that HighPoint Operating Corporation breached the contract by failing to use reasonable commercial efforts to deliver to Sterling at Sterling’s receipt points all quantities of gas not otherwise dedicated to other gas purchase agreements. We vigorously deny Sterling’s claims. Sterling seeks monetary damages in an amount not yet specified. On July 31, 2020, we filed a counterclaim against Sterling for breach of Sterling’s obligations under the Gas Purchase Agreement. We are seeking monetary damages in an amount not yet specified. The case is scheduled to go to trial in July 2021. At this time we are unable to determine whether any loss is probable or reasonably estimate a range of such loss, and accordingly we have not recognized any liability associated with this matter.
Disclosure of certain environmental matters is required when a governmental authority is a party to the proceedings and the proceedings involve potential monetary sanctions that we reasonably believe could exceed $300,000. We have received some Notices of Alleged Violations (“NOAV”) from the Colorado Oil and Gas Conservation Commission (“COGCC”) alleging violations of various Colorado statutes and COGCC regulations governing oil and gas operations. We are engaged in discussions regarding resolution of the alleged violations. We recognized $1.1 million during the year ended December 31, 2020 associated with the NOAVs, as they are probable and reasonably estimable.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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, 2021, there were 77 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, 2020.
Issuer Purchases of Equity Securities. The following table contains information about our acquisitions of equity securities during the three months ended December 31, 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, 2020 22 $ 10.95 - -
November 1 - 30, 2020 24 $ 3.75 - -
December 1 - 31, 2020 - $ - - -
Total 46 $ 7.20 - -
(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, 2015, 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, 2015.
2.Dividends are reinvested on the ex-dividend dates.
December 31,
2015 December 31,
2016 December 31,
2017 December 31,
2018 December 31,
2019 December 31,
HPR $ 100 $ 178 $ 131 $ 63 $ 43 $ 5
S&P SmallCap 600- Energy 100 138 101 58 49 30
S&P 500 100 112 136 130 171 203

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 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.
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,
2020 2019 2018
Estimated net proved reserves (MMBoe) 50.8 127.4 104.6
Standardized measure (1) (in millions)
$ 326.8 $ 973.9 $ 1,276.0
(1)December 31, 2020 reserves were based on average prices of $39.54 WTI per Bbl of oil, $1.99 Henry Hub per Mcf of natural gas and a percentage of the of the average oil price per Bbl of NGL. December 31, 2019 reserves were based on average prices of $55.85 WTI for oil, $2.58 Henry Hub for 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.
In early 2020, global health care systems and economies began to experience strain from the spread of COVID-19, a highly transmissible and pathogenic coronavirus (the “COVID-19 pandemic”). As the virus spread, global economic activity began to slow resulting in a decrease in demand for oil and natural gas. In response, OPEC+ initiated discussions to reduce production to support energy prices. With OPEC+ unable to agree on cuts, energy prices declined sharply during the first half of 2020. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy.
The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year ended December 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility.
As of February 4, 2021, we have hedged 3,098,000 barrels and 365,000barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively. However, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. This uncertainty increases the volatility and amplitude of risks we face as described in “Item 1A. Risk Factors”. If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.
We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of December 31, 2020. This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of December 31, 2020. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.
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.
Significant Business Developments
Pending Merger with Bonanza Creek Energy, Inc.
On November 9, 2020, we entered into a Merger Agreement with Bonanza Creek in which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. The Merger is expected to close in the first quarter of 2021 under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. HighPoint paid Bonanza Creek a transaction expense fee of $6.0 million in cash in consideration upon signing the Merger Agreement with Bonanza Creek. The Merger Agreement requires HighPoint to pay Bonanza Creek a termination fee of $15.0 million, less the $6.0 million transaction expense fee previously paid, if the agreement is terminated under certain circumstances as defined by the Merger Agreement. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.
Results of Operations
Year Ended December 31, 2020 Compared with Year Ended December 31, 2019
The following table sets forth selected operating data for the periods indicated:
Year Ended December 31, Increase (Decrease)
2020 2019 Amount Percent
($ in thousands, except per unit data)
Operating Results:
Operating Revenues:
Oil, gas and NGL production $ 249,192 $ 452,274 $ (203,082) (45) %
Other operating revenues, net 1,155 385 770 200 %
Total operating revenues $ 250,347 $ 452,659 $ (202,312) (45) %
Operating Expenses:
Lease operating expense $ 32,548 $ 37,796 $ (5,248) (14) %
Gathering, transportation and processing expense 18,467 10,685 7,782 73 %
Production tax expense (1)
(630) 23,541 (24,171) *nm
Exploration expense 192 143 49 34 %
Impairment and abandonment expense 1,285,085 9,642 1,275,443 *nm
Loss on sale of properties 4,777 2,901 1,876 65 %
Depreciation, depletion and amortization 148,995 321,276 (172,281) (54) %
Unused commitments 18,807 17,706 1,101 6 %
General and administrative expense (2)
43,167 44,759 (1,592) (4) %
Merger transaction expense 25,891 4,492 21,399 476 %
Other operating expenses (income), net (544) 402 (946) *nm
Total operating expenses $ 1,576,755 $ 473,343 $ 1,103,412 233 %
Production Data:
Oil (MBbls) 5,909 7,668 (1,759) (23) %
Natural gas (MMcf) 16,428 16,614 (186) (1) %
NGLs (MBbls) 2,352 2,101 251 12 %
Combined volumes (MBoe) 10,999 12,538 (1,539) (12) %
Daily combined volumes (Boe/d) 30,052 34,351 (4,299) (13) %
Average Realized Prices before Hedging:
Oil (per Bbl) $ 34.62 $ 52.86 $ (18.24) (35) %
Natural gas (per Mcf) 1.33 1.56 (0.23) (15) %
NGLs (per Bbl) 9.69 10.00 (0.31) (3) %
Combined (per Boe) 22.66 36.07 (13.41) (37) %
Average Realized Prices with Hedging:
Oil (per Bbl) $ 53.25 $ 54.39 $ (1.14) (2) %
Natural gas (per Mcf) 1.30 1.50 (0.20) (13) %
NGLs (per Bbl) 9.69 10.00 (0.31) (3) %
Combined (per Boe) 32.62 36.92 (4.30) (12) %
Average Costs (per Boe):
Lease operating expense $ 2.96 $ 3.01 $ (0.05) (2) %
Gathering, transportation and processing expense 1.68 0.85 0.83 98 %
Production tax expense (1)
(0.06) 1.88 (1.94) *nm
Depreciation, depletion and amortization 13.55 25.62 (12.07) (47) %
General and administrative expense (2)
3.92 3.57 0.35 10 %
*Not meaningful.
(1)See explanation of negative production tax expense for the year ended December 31, 2020 under Production Tax Expense below.
(2)Included in general and administrative expense is long-term cash and equity incentive compensation of $3.5 million (or $0.32 per Boe) and $8.6 million (or $0.69 per Boe) for the years ended December 31, 2020 and 2019, respectively.
Production Revenues and Volumes. Production revenues decreased to $249.2 million for the year ended December 31, 2020 from $452.3 million for the year ended December 31, 2019. The decrease in production revenues was due to a 37% decrease in the average realized prices per Boe before hedging, as well as a 12% decrease in production volumes. The decrease in average realized prices per Boe before hedging decreased production revenues by approximately $168.2 million, while the decrease in production volumes decreased production revenues by approximately $34.9 million.
Total production volumes of 11.0 MMBoe for the year ended December 31, 2020 decreased from 12.5 MMBoe for the year ended December 31, 2019 as a result of reducing our planned development in 2020 as well as deferring drilling and completion activity starting in May 2020.
Lease Operating Expense (“LOE”). LOE decreased to $2.96 per Boe for the year ended December 31, 2020 from $3.01 per Boe for the year ended December 31, 2019. The decrease per Boe for the year ended December 31, 2020 compared with the year ended December 31, 2019 is primarily related to operational efficiencies and a decrease in service industry costs due to a downturn in the industry.
Gathering, Transportation and Processing (“GTP”) Expense. GTP expense increased to $1.68 per Boe for the year ended December 31, 2020 from $0.85 per Boe for the year ended December 31, 2019.
Costs incurred to gather, transport and/or process our oil, gas and NGLs prior to the transfer of control to the customer are included in GTP expense. Costs incurred to gather, transport and/or process our oil, gas and NGLs after control has transferred to the customer are considered components of the consideration received from the customer and thus recorded in oil, gas and NGL production revenues. In general, based on specific contract arrangements, costs incurred associated with gas and NGLs in the Hereford Field are included in GTP expense and costs incurred associated with gas and NGLs in the Northeast Wattenberg Field are primarily 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 of the notes to the consolidated financial statements for additional information.
The increase in GTP per Boe for the year ended December 31, 2020 compared to 2019 was due to an increase from the Hereford Field associated with an unfavorable contract assumed in the 2018 Merger. The unfavorable contract amortization reduced GTP in 2019, but was fully amortized by the end of 2019 resulting in unfavorable contract pricing throughout 2020.
Production Tax Expense. Total production taxes decreased to negative $0.6 million for the year ended December 31, 2020 from $23.5 million for the year ended December 31, 2019. Production taxes are primarily based on the wellhead values of production, which exclude gains and losses associated with hedging activities. Production tax expense for both periods included an annual true up of Colorado ad valorem and severance tax based on actual assessments. Production taxes for the year ended December 31, 2020 also included a reduction of $5.4 million due to a change in estimate associated with our 2019 Colorado ad valorem tax that is due in 2021 and Colorado severance tax refunds of $1.8 million based on an audit of tax years 2015 to 2017. Excluding the ad valorem adjustments and the severance tax refunds associated with tax years 2015 to 2017, production taxes as a percentage of oil, natural gas and NGL sales before hedging adjustments were 6.5% and 6.3% for the years ended December 31, 2020 and 2019, respectively.
Impairment and Abandonment Expense. Market conditions led to a decline in the recoverability of the carrying value of our oil and gas properties during the quarter ended March 31, 2020. Since the carrying amount of our oil and gas properties was no longer recoverable, we impaired the carrying value to fair value. Therefore, we recognized non-cash impairment charges of $1.2 billion associated with proved oil and gas properties and $76.3 million associated with unproved oil and gas properties. In addition, as the result of our continuous review of our acreage position and future drilling plans, we recognized non-cash impairment related to our unproved oil and gas properties in the amount of $17.9 million during 2020 associated with certain leases in which the economics may not support renewal or extending at current contracted values. Our impairment and abandonment expense for the year ended December 31, 2020 and 2019 is summarized below:
Year Ended December 31,
2020 2019
(in thousands)
Impairment of proved oil and gas properties $ 1,188,566 $ -
Impairment of unproved oil and gas properties 94,209 3,854
Abandonment expense 2,310 5,788
Total impairment and abandonment expense $ 1,285,085 $ 9,642
We will continue to review our acreage position and future drilling plans as well as assess the carrying value of our properties relative to their estimated fair values. Lower sustained commodity prices or additional commodity price declines may lead to additional property impairment in future periods.
Depreciation, Depletion and Amortization (“DD&A”). DD&A decreased to $149.0 million for the year ended December 31, 2020 compared with $321.3 million for the year ended December 31, 2019. The decrease of $172.3 million was the result of a 47% decrease in the DD&A rate and a 12% decrease in production for the year ended December 31, 2020 compared with the year ended December 31, 2019. The decrease in the DD&A rate accounted for a $132.9 million decrease in DD&A expense while the decrease in production accounted for a $39.4 million decrease in DD&A expense.
Under successful efforts accounting, depletion expense is calculated using the units-of-production method on the basis of some reasonable aggregation of properties with a common geological structural feature or stratigraphic condition, such as a reservoir or field. The capital expenditures for proved properties for each field compared to the proved reserves corresponding to each producing field determine a depletion rate for current production. For the year ended December 31, 2020, the relationship of historical capital expenditures, proved reserves and production from certain producing fields yielded a depletion rate of $13.55 per Boe compared with $25.62 per Boe for the year ended December 31, 2019. The decrease in the depletion rate of 47% was a result of recognizing a $1.2 billion impairment associated with our proved oil and gas properties during the quarter ended March 31, 2020.
Unused Commitments. Unused commitments expense of $18.8 million and $17.7 million for the years ended December 31, 2020 and 2019, respectively, primarily related to gas transportation contracts. During March 2010, we entered into two firm natural gas pipeline transportation contracts to provide a guaranteed outlet for production from the West Tavaputs area of the Uinta Basin and the Gibson Gulch area of the Piceance Basin. These transportation contracts were not included in the sales of these assets in December 2013 and September 2014, respectively. Both firm transportation contracts require the pipeline to provide transportation capacity and require us to pay monthly transportation charges regardless of the amount of pipeline capacity utilized. The agreements expire July 31, 2021.
General and Administrative Expense. General and administrative expense decreased to $43.2 million for the year ended December 31, 2020 from $44.8 million for the year ended December 31, 2019. General and administrative expense on a per Boe basis increased to $3.92 for the year ended December 31, 2020 from $3.57 for the year ended December 31, 2019. The decrease in general and administrative expense for the year ended December 31, 2020 was due to a decrease in long-term cash and equity incentive compensation discussed below, partially offset by an increase in legal and advisory fees associated with strategic plans that were contemplated, but not completed. Legal and advisory fees that resulted in the Merger Agreement discussed in Note 1 of the notes to the consolidated financial statements were recognized in merger transaction expense discussed below.
Included in general and administrative expense is long-term cash and equity incentive compensation of $3.5 million and $8.6 million for the years ended December 31, 2020 and 2019, respectively. The decrease for the year ended December 31, 2020 was primarily due to a reduction in overall equity awards granted during the year ended December 31, 2020. In addition, we cancelled all performance cash units during the year ended December 31, 2020. The components of long-term cash and equity incentive compensation for each of the years ended December 31, 2020 and 2019 are shown in the following table:
Year Ended December 31,
2020 2019
(in thousands)
Nonvested common stock $ 4,106 $ 6,601
Nonvested common stock units 543 1,177
Nonvested performance cash units (1)
(1,162) 844
Total $ 3,487 $ 8,622
(1)The nonvested performance cash units are accounted for as liability awards. The expense for the period will increase or decrease based on updated fair values of these awards at each reporting date. As of December 31, 2020, all nonvested performance cash units were cancelled resulting in a reversal of expense and liability balances.
Merger Transaction Expense. Merger transaction expense was $25.9 million and $4.5 million for the years ended December 31, 2020 and December 31, 2019, respectively. Transaction expenses included consulting, advisory, legal and other merger-related fees associated with the Merger Agreement for the year December 31, 2020 and the 2018 Merger for the year ended December 31, 2019. See Note 4 of the notes to the consolidated financial statements for additional information.
Commodity Derivative Gain (Loss). Commodity derivative gain was $124.9 million for the year ended December 31, 2020 compared with a loss of $99.0 million for the year ended December 31, 2019. The gain or loss on commodity derivatives is related to fluctuations of oil and natural gas future pricing compared to actual pricing of commodity hedges in place as of December 31, 2020 and 2019 or during the periods then ended.
The fair value of our open but not yet settled derivative contracts is based on an income approach using various assumptions, such as quoted forward prices for commodities, risk-free discount rates, volatility factors and time value factors. The mark-to-market fair value of the open commodity derivative contracts will generally be inversely related to the price movement of the underlying commodity. If commodity price trends reverse from period to period, prior unrealized gains may become unrealized losses and vice versa. Higher underlying commodity price volatility will generally lead to higher volatility in our unrealized gains and losses and, by association, the fair value of our commodity derivative contracts. These unrealized gains and losses will impact our net income in the period reported. The mark-to-market fair value can create non-cash volatility in our reported earnings during periods of commodity price volatility. We have experienced such volatility due to the COVID-19 pandemic and are likely to experience it in the future. Gains on our derivatives generally indicate lower wellhead revenues in the future while losses indicate higher future wellhead revenues.
The table below summarizes our commodity derivative gains and losses that were recognized in the periods presented:
Year Ended December 31,
2020 2019
(in thousands)
Realized gain (loss) on derivatives (1)
$ 109,583 $ 10,667
Prior year unrealized (gain) loss transferred to realized (gain) loss (1)
495 (81,166)
Unrealized gain (loss) on derivatives (1)
14,847 (28,454)
Total commodity derivative gain (loss) $ 124,925 $ (98,953)
(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.
In 2020, approximately 91% of our oil volumes and 33% of our natural gas volumes were subject to financial hedges, which resulted in an increase in oil income of $110.1 million and a decrease in natural gas income of $0.5 million after settlements. In 2019, approximately 88% of our oil volumes and 19% of our natural gas volumes were covered by financial hedges, which resulted in an increase in oil income of $11.7 million and a decrease natural gas income of $1.0 million after settlements.
Income Tax (Expense) Benefit. For the year ended December 31, 2020, as a result of the $1.3 billion impairment, we determined that it was not more likely than not that we would be able to realize existing 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 and 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 recorded an income tax benefit of $95.9 million. A $1.6 million deferred tax liability has been recorded for projected taxable income in future periods in which only 80% of taxable income can be offset by net operating losses.
For the year ended December 31, 2019, we determined 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 2018 Merger and their classification as proved or unproved, current and projected future taxable income and tax planning strategies.
Year Ended December 31, 2019 Compared with Year Ended December 31, 2018
A discussion of our results of operations for the year ended December 31, 2019 compared with December 31, 2018 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, 2019.
Capital Resources and Liquidity
Current Financial Condition and Liquidity
We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of December 31, 2020. This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of December 31, 2020. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.
In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a “going concern” (“going concern opinion”) in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion.
At December 31, 2020, we had cash and cash equivalents of $24.7 million and $140.0 million outstanding under the Credit Facility. At December 31, 2019, we had cash and cash equivalents of $16.4 million and $140.0 million outstanding under our Credit Facility. As part of our regular semi-annual redeterminations, the elected commitment amount on our Credit Facility was reduced to $300.0 million on May 21, 2020 and to $185.0 million on November 3, 2020. Our available borrowing capacity as of December 31, 2020 was $24.0 million, after taking into account $21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations.
Sources of Liquidity and Capital Resources
Our primary sources of liquidity since our formation have been net cash provided by operating activities, including commodity hedges, sales and other issuances of equity and debt securities, bank credit facilities and sales of interests in properties. Our primary use of capital has been for the development, exploration and acquisition of oil and natural gas properties. As we pursue profitable reserves and production growth, we continually monitor the capital resources available to us to meet our future financial obligations, fund planned capital expenditure activities and ensure adequate liquidity.
We may from time to time seek to retire, purchase or otherwise refinance our outstanding debt securities through cash purchases and/or exchanges, in open market purchases, privately negotiated transactions, exchange offers or otherwise. Any
such transactions will depend on prevailing market conditions, our liquidity requirements, contractual restrictions and other factors. On November 9, 2020, we entered into a Merger Agreement with Bonanza Creek pursuant to which HighPoint’s debt will be restructured and HighPoint will merge with a wholly owned subsidiary of Bonanza Creek, with HighPoint continuing its existence as the surviving company following the merger and continuing as a wholly owned subsidiary of Bonanza Creek. The Merger is expected to close in the first quarter under the Exchange Offer or in the first or second quarter of 2021 under the Prepackaged Plan. See “Items 1 and 2 Business and Properties - Business - Significant Business Developments” for additional information.
Our future success in growing proved reserves and production will be highly dependent on capital resources being available to us. Given the levels of market volatility and disruption due to the COVID-19 pandemic and other recent macro and microeconomic factors, the availability of funds from those markets has diminished substantially. Further, arising from concerns about the stability of financial markets generally and the solvency of borrowers specifically, the cost of accessing the credit markets has increased as many lenders have raised interest rates, enacted tighter lending standards, or altogether ceased to provide funding to borrowers.
Cash Flow from Operating Activities
Net cash provided by operating activities was $129.0 million, $278.6 million and $231.4 million in 2020, 2019 and 2018, respectively. The changes in net cash provided by operating activities are discussed above in “Results of Operations”. The decrease in cash provided by operating activities from 2019 to 2020 was primarily due to a decrease in production revenues and a decrease in working capital changes due to the timing of cash receipts and disbursements, partially offset by an increase in cash settlements of derivatives.
Commodity Hedging Activities
Our operating cash flow is sensitive to many variables, the most significant of which are the prices we receive for the oil, natural gas and NGLs we produce. Prices for these commodities are determined primarily by prevailing market conditions. National and worldwide economic activity and political stability, weather, infrastructure capacity to reach markets, supply levels and other variable factors influence market conditions for these products. These factors, which include the COVID-19 pandemic, are beyond our control and are difficult to predict.
To mitigate some of the potential negative impact on cash flow caused by changes in oil, natural gas and NGL prices, we have entered into financial commodity swap, swaption and cashless collar contracts to receive fixed prices for a portion of our production. At December 31, 2020, we had in place crude oil swaps covering portions of our 2021 and 2022 production, natural gas swaps covering portions of our 2021 and 2022 production, oil roll swaps covering portions of our 2021 and 2022 production, crude oil swaptions covering portions of our 2022 production and natural gas cashless collars covering portions of our 2021 production. Due to the uncertainty surrounding the COVID-19 pandemic, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future.
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, 2021.
Contract Total
Hedged
Volumes Quantity
Type Weighted
Average Fixed Price Weighted Average Floor Price Weighted Average Ceiling Price Index
Price (1)
Swaps
Oil 3,098,000 Bbls $ 54.30 WTI
Natural Gas 5,790,000 MMBtu $ 2.13 NWPL
Oil 365,000 Bbls $ 50.15 WTI
Natural Gas 3,650,000 MMBtu $ 2.13 NWPL
Oil Roll Swaps (2)
Oil 1,554,500 Bbls $ 0.14 WTI
Oil 730,000 Bbls $ 0.22 WTI
Swaptions (3)
Oil 1,092,000 Bbls $ 55.08 WTI
Cashless Collars
Natural Gas 1,800,000 MMBtu $ 2.00 $ 4.25 NWPL
(1)WTI refers to West Texas Intermediate price as quoted on the New York Mercantile Exchange. NWPL refers to the Northwest Pipeline Corporation price as quoted in Platt’s Inside FERC on the first business day of each month.
(2)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month price. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
(3)These swaptions may become effective fixed-price swaps at the counterparty’s election on December 31, 2021.
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 Credit Facility, affiliates of lenders in the Credit Facility or potential lenders in the 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 Credit Facility. We have set-off provisions in our derivative contracts with lenders under our Credit Facility which, in the event of a counterparty default, allow us to set-off amounts owed to the defaulting counterparty under the Credit Facility or other obligations against monies owed to us under the derivative contracts. Where the counterparty is not a lender under the Credit Facility, we may not be able to set-off amounts owed by us under the 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 2020 2019 2018
(in millions)
DJ $ 97.3 $ 355.0 $ 508.2
Other 2.2 6.0 0.7
Total (1)(2)
$ 99.5 $ 361.0 $ 508.9
Year Ended December 31,
2020 2019 2018
(in millions)
Acquisitions of proved and unproved properties and other real estate
$ - $ 4.7 $ 19.9
Drilling, development, exploration and exploitation of oil and natural gas properties
95.5 319.3 448.9
Gathering and compression facilities 2.8 20.4 37.1
Geologic and geophysical costs 0.6 12.0 2.3
Furniture, fixtures and equipment 0.6 4.6 0.7
Total (1)(2)
$ 99.5 $ 361.0 $ 508.9
(1)Includes exploration and abandonment expense, which are expensed under successful efforts accounting, of $2.5 million, $5.9 million and $0.8 million for the years ended December 31, 2020, 2019 and 2018, 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 2018 Merger for the year ended December 31, 2018.
Our current estimated capital expenditure budget for the first quarter of 2021 is approximately $3.0 million, primarily associated with flowback on previously completed wells. In addition, in November 2020 we entered into the Merger Agreement with Bonanza Creek, which restricts our near-term capital spending levels and does not allow for drilling or completion operations.
Capital expenditures decreased to $99.5 million for the year ended December 31, 2020 from $361.0 million for the year ended December 31, 2019. The decrease was due to a reduction in planned development for 2020 as well as deferring drilling and completion activity starting in May 2020 due to the COVID-19 pandemic.
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.
Financing Activities
Our outstanding debt is summarized below:
As of December 31, 2020 As of December 31, 2019
Maturity Date Principal Debt Issuance Costs Carrying
Amount Principal Debt Issuance Costs Carrying
Amount
(in thousands)
Amended Credit Facility September 14, 2023 $ 140,000 $ - $ 140,000 $ 140,000 $ - $ 140,000
7.0% Senior Notes October 15, 2022 350,000 (1,535) 348,465 350,000 (2,372) 347,628
8.75% Senior Notes June 15, 2025 275,000 (3,031) 271,969 275,000 (3,717) 271,283
Total Long-Term Debt (1)
$ 765,000 $ (4,566) $ 760,434 $ 765,000 $ (6,089) $ 758,911
(1)See Note 5 of the notes to the consolidated financial statements for additional information.
Credit Facility. On May 21, 2020, as part of a regular semi-annual redetermination, our Credit Facility was amended. Among other things, the amendment decreased the aggregate elected commitment amount and the borrowing base from $500.0 million to $300.0 million, increased the applicable margins for interest and commitment fee rates and added provisions requiring the availability under the Credit Facility to be at least $50.0 million and the Company’s weekly cash balance (subject to certain exceptions) to not exceed $35.0 million. On November 2, 2020, as part of another regular semi-annual redetermination, the Credit Facility was further amended. Among other things, the amendment reduced the Company’s aggregate elected commitment amount to $185.0 million, reduced the borrowing base to $200.0 million and removed the provisions requiring availability under the Credit Facility to be at least $50.0 million. In addition, provisions were amended to
prohibit the Company from incurring any additional indebtedness. The Company had $140.0 million outstanding as of both December 31, 2020 and December 31, 2019. The Company’s available borrowing capacity under the Credit Facility as of December 31, 2020 was $24.0 million, after taking into account $21.0 million of outstanding irrevocable letters of credit, which were issued as credit support for future payments under contractual obligations. Our available borrowing capacity as of the date of this filing, February 24, 2021, was $34.9 million, after taking into account outstanding irrevocable letters of credit of $18.1 million.
While the stated maturity date in the Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022.
The borrowing base is determined at the discretion of the lenders and is subject to regular redetermination around April and October of each year, as well as following any property sales. The lenders can also request an interim redetermination during each six month period. If the borrowing base is reduced below the then-outstanding amount under the Credit Facility, we will be required to repay the excess of the outstanding amount over the borrowing base over a period of four months. The borrowing base is computed based on proved oil, natural gas and NGL reserves that have been mortgaged to the lenders, hedge positions and estimated future cash flows from those reserves calculated using future commodity pricing provided by the lenders, as well as any other outstanding debt.
Going Concern. We have financial covenants associated with our Credit Facility that are measured each quarter. As discussed in the “Going Concern” section in Note 2 of the notes to the consolidated financial statements, based on our forecasted cash flow analysis for the twelve month period subsequent to the date of this filing, it is probable we will breach a financial covenant under our Credit Facility in the third quarter of 2021. However, timing could change as a result of changes in our business and the overall economic environment. Violation of any covenant under the Credit Facility provides the lenders with the option to accelerate the maturity of the Credit Facility, which carries a balance of $140.0 million as of December 31, 2020. This would, in turn, result in cross-default under the indentures to our senior notes, accelerating the maturity of the senior notes, which have a principal balance outstanding of $625.0 million as of December 31, 2020. We do not have sufficient cash on hand or available liquidity that can be utilized to repay the outstanding debt in the event of default. These conditions and events raise substantial doubt about our ability to continue as a going concern.
In addition, our independent auditor has included an explanatory paragraph regarding our ability to continue as a “going concern” (“going concern opinion”) in its report in this Annual Report on Form 10-K, which would accelerate a default under our Credit Facility to the filing date of this Annual Report on Form 10-K. However, we obtained a waiver from our lenders removing the default associated with this going concern opinion.
Guarantor Structure. The issuer of our 7.0% Senior Notes and 8.75% Senior Notes is HighPoint Operating Corporation (f/k/a Bill Barrett), or the Subsidiary Issuer. Pursuant to supplemental indentures entered into in connection with the 2018 Merger, HighPoint Resources Corporation, or the Parent Guarantor, became a guarantor of the 7.0% Senior Notes and the 8.75% Senior Notes in March 2018. In addition, Fifth Pocket Production, LLC, or the Subsidiary Guarantor, became a subsidiary of Subsidiary Issuer on August 1, 2019 and also guarantees the 7.0% Senior Notes and the 8.75% Senior Notes. The Parent Guarantor and the Subsidiary Guarantor, on a joint and several basis, fully and unconditionally guarantee the debt securities of the Subsidiary Issuer. We have no other subsidiaries. All covenants in the indentures governing the notes limit the activities of the Subsidiary Issuer and the Subsidiary Guarantor, including limitations on the ability to pay dividends, incur additional indebtedness, make restricted payments, create liens, sell assets or make loans to the Parent Guarantor, but in most cases the covenants in the indentures are not applicable to the Parent Guarantor.
In March 2020, the SEC issued a final rule, Financial Disclosures About Guarantors and Issuers of Guaranteed Securities and Affiliates Whose Securities Collateralize a Registrant’s Securities, which amends the disclosure requirements related to certain registered securities which currently require separate financial statements for subsidiary issuers and guarantors of registered debt securities unless certain exceptions are met. Alternative disclosures are available for each subsidiary issuer/guarantor when they are consolidated and the parent company either issues or guarantees, on a full and unconditional basis, the guaranteed securities. If a registrant qualifies for alternative disclosure, the registrant may omit summarized financial information when not material and instead provide narrative disclosure of the guarantor structure, including terms and conditions of the guarantees.
We qualify for alternative disclosure, and therefore, we are no longer presenting condensed consolidating financial information for the Parent Guarantor, Subsidiary Issuer, or the Subsidiary Guarantor of our debt securities. The assets, liabilities and results of operations of the issuer and guarantors of the guaranteed securities on a combined basis are not materially different than corresponding amounts presented in the consolidated financial statements of the Parent Guarantor as all of the material operating assets and liabilities, and all of our material operations reside within the subsidiary issuer.
Credit Ratings. Our credit risk is evaluated by two independent rating agencies based on publicly available information and information obtained during our ongoing discussions with the rating agencies. Moody’s Investor Services and Standard & Poor’s Rating Services currently rate our 7.0% Senior Notes and 8.75% Senior Notes and have assigned a credit rating. We do not have any credit rating triggers that would accelerate the maturity of amounts due under our 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 could be affected by our credit rating at the time any such financing activities are conducted.
Contractual Obligations. A summary of our contractual obligations as of and subsequent to December 31, 2020 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)(2)
$ 306 $ - $ 140,000 $ - $ - $ - $ 140,306
7.0% Senior Notes (2)(3)
24,500 374,500 - - - - 399,000
8.75% Senior Notes (2)(4)
24,063 24,063 24,063 24,063 287,031 - 383,283
Firm transportation agreements (5)
19,549 13,064 14,600 14,640 4,800 - 66,653
Asset retirement obligations (6)
2,020 2,000 2,020 2,114 2,406 16,285 26,845
Derivative liability (7)
1,414 2,887 - - - - 4,301
Operating leases (8)
2,691 2,413 2,167 2,078 2,196 5,380 16,925
Other (9)
3,651 11,485 16,345 - - - 31,481
Total $ 78,194 $ 430,412 $ 199,195 $ 42,895 $ 296,433 $ 21,665 $ 1,068,794
(1)Included in notes payable is the outstanding principal amount under our Credit Facility due September 14, 2023. This table does not include future commitment fees, interest expense or other fees on our Credit Facility because the Credit Facility is a floating rate instrument, and we cannot determine with accuracy the timing of future loan advances, repayments or future interest rates to be charged. While the stated maturity date in the Credit Facility is September 14, 2023, the maturity date is accelerated if we have more than $100.0 million of “Permitted Debt” or “Permitted Refinancing Debt” (as those terms are defined in the Credit Facility) that matures prior to December 14, 2023. If that is the case, the accelerated maturity date is 91 days prior to the earliest maturity of such Permitted Debt or Permitted Refinancing Debt. Because our 7.0% Senior Notes will mature on October 15, 2022, the aggregate amount of those notes exceeds $100.0 million and the notes represent “Permitted Debt”, the maturity date specified in the Credit Facility is accelerated to the date that is 91 days prior to the maturity date of those notes, or July 16, 2022. Also included in notes payable is interest on $21.0 million irrevocable letters of credit, which will continue decrease ratably per month until expiring in August 2021. Interest accrues at 3.25% and 0.125% per annum for participation fees and fronting fees, respectively.
(2)The payment dates could be accelerated. See the “Going Concern” section in Note 2 of the notes to the consolidated financial statements for additional information.
(3)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 of the notes to the consolidated financial statements for additional information.
(4)The aggregate principal amount of our 8.75% Senior Notes is $275.0 million. We are obligated to make semi-annual interest payments through maturity on June 15, 2025 equal to $12.0 million. See Note 5 of the notes to the consolidated financial statements for additional information.
(5)We have entered into contracts that provide firm transportation capacity on oil and gas pipeline systems. The contracts require us to pay transportation demand charges regardless of the amount we deliver to the pipeline.
(6)Neither the ultimate settlement amounts nor the timing of our asset retirement obligations can be precisely determined in advance. See “Critical Accounting Policies and Estimates” below for a more detailed discussion of the nature of the accounting estimates involved in estimating asset retirement obligations.
(7)Derivative liability represents the net fair value for oil, gas, and NGL commodity derivatives presented as liabilities in our Consolidated Balance Sheets as of December 31, 2020. The ultimate settlement amounts of our derivative liabilities are unknown because they are subject to continuing market fluctuations. See “Critical Accounting Policies and Estimates”
below and “Commodity Hedging Activities” above for a more detailed discussion of the nature of the accounting estimates involved in valuing derivative instruments.
(8)Operating leases primarily includes office leases. Also included are leases of operations equipment which are shown as gross amounts that we are financially committed to pay. However, we will record in our financial statements our proportionate share based on our working interest, which will vary from property to property.
(9)Includes $10.2 million for the year ended December 31, 2022 and $15.3 million for the year ended December 31, 2023 related to a drilling commitment with a joint interest partner which requires us to drill and complete two wells by July 2022 and three wells by 2023. If the drilling commitment is not met, we must return the associated leases that are not held by production to the joint interest partner, which cover approximately 13,000 acres. The Company is also party to minimum volume commitments for the delivery of natural gas volumes to midstream entities for gathering, processing and capital reimbursements as well as minimum volume commitments to purchase fresh water from water suppliers. These commitments require the Company to pay a fee associated with the minimum volumes regardless of the amount delivered.
Off-Balance Sheet Arrangements
We do not have any off-balance sheet arrangements as of December 31, 2020.
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 conduct, 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. The movement has found some success in persuading governments, investors and corporations to consider measures to reduce the use of fossil fuels in the future. Examples include local measures to prohibit the use of natural gas for heating, hot water and stoves in new construction; GM’s announcement that it will phase-out gasoline engines in its cars by 2035; and increased pressure on corporations to reduce emissions from the investment community, notably Black Rock and Vanguard. These developments portend a risk that demand for fossil fuels may be significantly reduced in the coming decades. 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.
The following trends and uncertainties are related to the COVID-19 pandemic:
Declining Commodity Prices. Energy prices declined sharply during the first half of 2020 due to the COVID-19 pandemic. While prices partially recovered during the second half of 2020, uncertainties related to the demand for oil and natural gas remain as the COVID-19 pandemic continues to impact the world economy. The impacts of substantially lower oil, natural gas and NGL prices on our results of operations for the year ended December 31, 2020 were mostly mitigated by hedges in place on 91% of our oil production and 33% of our natural gas production. However, the economics of our existing wells and planned future development were adversely affected, which led to impairments of our proved and unproved oil and gas properties, reductions to our oil and gas reserve quantities and reductions to the borrowing capacity on our Credit Facility. As of February 4, 2021, we have hedged 3,098,000 barrels and 365,000 barrels of our expected 2021 and 2022 oil production, respectively, and 7,590,000 MMbtu and 3,650,000 MMbtu of our expected 2021 and 2022 natural gas production, respectively. However, we may be unable to obtain additional hedges at favorable price levels in the near or foreseeable future. There is uncertainty around the timing of recovery of the global economy from COVID-19 and its effects on the supply and demand for oil, natural gas and NGLs. This uncertainty increases the volatility and amplitude of risks we face as described in “Item 1A. Risk Factors”. If energy prices do not improve, our capital availability, liquidity and profitability will continue to be adversely affected, particularly after our current hedges are realized in 2021.
Employee Health and Safety. The health and safety of our employees and the community is our highest priority. We are also cognizant that supplying reliable energy to our communities and the nation is an essential function. The federal government, through the Cybersecurity and Infrastructure Security Administration, as well as Colorado state and local “stay-at-home” orders, have provided exemptions for oil and gas workers.
Under our business continuity plan, we were rapidly able to switch to remote operations in response to the COVID-19 pandemic in early March. We successfully transitioned to full remote access and operations, in both the Denver headquarters office and at the field level. The successful transition to remote operations was virtually seamless. From mid-March 2020 through February 2021, based on management’s continuous risk assessments, employees were either fully remote or on a staggered schedule so that approximately 50% of the work force was in the office on a daily basis.
Supply Chain Issues. We have not experienced any recent challenges with respect to obtaining oil field goods and services. However, as oil service and supply companies cut work force and stack rigs and frac fleets, there is the potential for challenges on this front when activity begins to ramp up, although the related timing is highly uncertain.
Critical Accounting Policies and Estimates
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.
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 settlements 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 as of the applicable measurement 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 is 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.
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, 2020.
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, 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 our 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, 2020.
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 2020.
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 the consolidated financial statements.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 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, 2020, our income before taxes would have decreased by approximately $0.3 million for each $5.00 per barrel decrease in crude oil prices, $1.1 million for each $0.10 decrease per MMBtu in natural gas prices and $2.2 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, swaptions or cashless collars. A swap allows us to receive a fixed price for our production and pay a variable market price to the counterparty. A swaption allows the counterparty, on a specific date, to extend an existing fixed-price swap for a certain period of time or to increase the notional volumes of an existing fixed-price swap. A cashless collar establishes a floor and a ceiling price, which allows us to receive the difference between the floor price and the variable market price if the variable market price is below the floor price. However, we will pay the difference between the ceiling price and the variable market price if the variable market price is above the ceiling. No amounts are paid or received if the variable market price is between the floor and ceiling prices. We have also entered into crude oil swaps to fix the differential in pricing between the NYMEX WTI calendar month average and the physical crude delivery month price (“oil roll swaps”). 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, 2021, we have swap and swaption contracts in place to hedge the following volumes for the 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 2021 For the Year 2022
Derivative
Volumes Weighted Average
Price Derivative
Volumes Weighted Average
Price
Swaps
Oil (Bbls) 3,098,000 $ 54.30 365,000 $ 50.15
Natural Gas (MMbtu) 5,790,000 2.13 3,650,000 2.13
Oil Roll Swaps (1)
Oil (Bbls) 1,554,500 0.14 730,000 0.22
Swaptions (2)
Oil (Bbls) - - 1,092,000 55.08
(1)These contracts establish a fixed amount for the differential between the NYMEX WTI calendar month average and the physical crude oil delivery month price. The weighted average differential represents the amount of reduction to NYMEX WTI prices for the notional volumes covered by the swap contracts.
(2)These swaptions may become effective fixed-price swaps at the counterparty’s election on December 31, 2021.
As of February 4, 2021, the Company had cashless collars in place to hedge the following volumes for the periods indicated:
For the Year 2021
Derivative Volumes Weighted Average Floor Weighted Average Ceiling
Cahless Collars
Natural Gas (MMbtu) 1,800,000 $ 2.00 $ 4.25

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
Item 8. Financial Statements and Supplementary Data.
The information required by this item is included below in “Item 15. Exhibits, Financial Statement Schedules”.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
Item 9A. Controls and Procedures.
Evaluation of Disclosure Controls and Procedures. As of December 31, 2020, 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, 2020.
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.
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, 2020, our internal control over financial reporting is effective.
Changes in Internal Controls. There was no change in our internal control over financial reporting during the fourth fiscal quarter of 2020 that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other Information.
Paul W. Geiger, Chief Operating Officer of the Company, has left the Company effective as of February 23, 2021 (the “Effective Date”). Mr. Geiger’s separation is not the result of any disagreement with the Company. Pursuant to a compensation agreement dated as of October 9, 2020, Mr. Geiger was paid $1,731,490, subject to clawback of the after-tax amount of the payment in the event of certain terminations of employment, including a voluntary resignation. In connection with Mr. Geiger’s separation, Mr. Geiger will be required to repay $79,002 to the Company, and the Board of Directors of the Company has taken action to waive the remaining clawback obligation, subject to his execution and non-revocation of a general release of claims in favor of the Company.
On the Effective Date, R. Scot Woodall, the Company’s Chief Executive Officer and President, will serve as the Company’s principal operating officer. Mr. Woodall, age 59, has served as the Company’s Chief Executive Officer and President since January 2013. Mr. Woodall has served in various positions of increasing responsibility since joining the Company’s predecessor, Bill Barrett Corporation, in 2007. No new compensatory arrangements will be entered into with Mr. Woodall in connection with his appointment as the Company’s principal operating officer.
PART III

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
Item 10. Directors, Executive Officers and Corporate Governance.
The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after December 31, 2020.

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ITEM 11. EXECUTIVE COMPENSATION
Item 11. Executive Compensation.
The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after December 31, 2020.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.
The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after December 31, 2020.
Equity Compensation Plan Information
The following table provides aggregate information presented as of December 31, 2020 with respect to all compensation plans under which equity securities are authorized for issuance.
(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
- $ - 232,311
Equity compensation plans not approved by shareholders
- - -
Total
- $ - 232,311

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
Item 13. Certain Relationships and Related Transactions and Director Independence.
The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after December 31, 2020.

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
Item 14. Principal Accounting Fees and Services.
The information required by this item will be incorporated by reference in a future filing with the SEC within 120 days after December 31, 2020.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, Financial Statement Schedules.
(a)(1) and (a)(2) Financial Statements and Financial Statement Schedules.
Report of Independent Registered Public Accounting Firm 64
Consolidated Balance Sheets as of December 31, 2020 and 2019 67
Consolidated Statements of Operations for the years ended December 31, 2020, 2019 and 2018 68
Consolidated Statements of Cash Flows for the years ended December 31, 2020, 2019 and 2018 69
Consolidated Statements of Stockholders' Equity (Deficit) for the years ended December 31, 2020, 2019 and 2018 70
Notes to Consolidated Financial Statements 71
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.
(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.]
2.2 Agreement and Plan of Merger, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc. and HighPoint Resources Corporation. [Incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
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.]
3.1.1 Certificate of Amendment to the Amended and Restated Certificate of Incorporation of HighPoint Resources Corporation, as filed on October 29, 2020 with the State of Delaware. [Incorporated by reference to Exhibit 3.1 of our Current Report on Form 8-K filed with the Commission on October 30, 2020.]
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. [Incorporated by reference to Exhibit 4.1.1 to our Annual Report on Form 10-K filed with the Commission on February 26, 2020.]
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.]
Exhibit
Number Description of Exhibits
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.]
10.1.1 First Amendment to Fourth Amended and Restated Credit Agreement, dated as of May 21, 2020, among HighPoint Resources Corporation, as guarantor, HighPoint Operating Corporation, as borrower, borrower’s subsidiary, and the banks named therein. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on May 26, 2020.]
10.1.2 Second Amendment to Fourth Amended and Restated Credit Agreement, dated as of November 2, 2020, among HighPoint Resources Corporation, as guarantor, HighPoint Operating Corporation, as borrower, borrower's subsidiary, and the lenders named therein. [Incorporated by reference to Exhibit 10.1 to our Currrent Report on Form 8-K filed with the Commission on November 6, 2020.]
10.1.3 Consent and Agreement, dated as of February 1, 2021, by and among HighPoint Operating Corporation, HighPoint Resources Corporation, the Guarantors party thereto, the Lenders party thereto and JPMorgan Chase Bank, N.A., as administrative agent. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on February 5, 2021.]
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+ 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.]
10.3.1+ 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.]
Exhibit
Number Description of Exhibits
10.3.2+ Second Amendment to the 2012 Equity Incentive Plan. [Incorporated by reference to Appendix A of our Proxy Statement on Schedule 14A filed with the Commission on March 18, 2020.]
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+ Form of Director’s Restricted Common Stock Unit Award Agreement. [Incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
10.6+ Form of Performance Unit Grant Agreement. [Incorporated by reference to Exhibit 10.2 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
10.7+ Form of Restricted Common Stock Award Agreement. [Incorporated by reference to Exhibit 10.3 of our Quarterly Report on Form 10-Q filed with the Commission on November 9, 2020.]
10.8+ 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.]
10.9+ 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.]
10.10 Form of Stockholders Agreement between Red Rider Holdco, Inc., Fifth Creek Energy Company, LLC, and NGP Natural Resources XI, L.P. [Incorporated by reference to Exhibit 10.7 to our Annual Report on Form 10-K filed with the Commission on February 26, 2020.]
10.10.1 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.]
10.10.2 Amendment No. 1 to Stockholders Agreement. [Incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed with the Commission on February 26, 2020.]
10.11+ 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.]
10.12+* Form of Compensation Agreement, Retention and Sale Payment.
10.13 Voting and Support Agreement, dated as of November 9, 2020, by and among Bonanza Creek Energy, Inc., Boron Merger Sub, Inc., HighPoint Resources Corporation and Fifth Creek Energy Company, LLC. [Incorporated by reference to Exhibit 10.1 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
10.14 Transaction Support Agreement, dated as of November 9, 2020, by and among HighPoint Resources Corporation, HighPoint Resources Corporation, HighPoint Operating Corporation, Fifth Pocket Production, LLC, HPR Consenting 7% Noteholders, HPR Consenting 8.75% Noteholders, and HPR Consenting Shareholders (as such terms are defined therein). [Incorporated by reference to Exhibit 10.2 of our Current Report on Form 8-K filed with the Commission on November 9, 2020.]
21* Subsidiaries of the Registrant.
22* Subsidiary Guarantors and Issuers of Guaranteed Securities.
Exhibit
Number Description of Exhibits
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 20, 2021, 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
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.