SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
|☒||ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the fiscal year ended December 31, 2020
|☐||TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934|
For the transition period from to
Commission File Number: 001-32886
CONTINENTAL RESOURCES, INC.
(Exact name of registrant as specified in its charter)
|(State or other jurisdiction of incorporation or organization)|| ||(I.R.S. Employer Identification No.)|
|20 N. Broadway,||Oklahoma City,||Oklahoma||73102|
|(Address of principal executive offices)||(Zip Code)|
Registrant’s telephone number, including area code: (405) 234-9000
Securities registered pursuant to Section 12(b) of the Act:
|Title of each class|| Trading symbol(s)||Name of each exchange on which registered|
|Common Stock, $0.01 par value||CLR||New York Stock Exchange|
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes x No ¨
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ¨ No x
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes x No ¨
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes x No ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.
|Large accelerated filer|| ||x|| ||Accelerated filer|| ||☐|
|Non-accelerated filer|| ||☐|| ||Smaller reporting company|| ||☐|
|Emerging growth company||☐|
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨
Indicate by check mark whether the registrant has filed a report on and attestation to its management's assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No x
The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2020 was approximately $1.4 billion, based upon the closing price of $17.53 per share as reported by the New York Stock Exchange on such date.
365,193,888 shares of our $0.01 par value common stock were outstanding on January 31, 2021.
DOCUMENTS INCORPORATED BY REFERENCE
Portions of the definitive Proxy Statement of Continental Resources, Inc. for the Annual Meeting of Shareholders to be held in May 2021, which will be filed with the Securities and Exchange Commission within 120 days after the end of the fiscal year, are incorporated by reference into Part III of this Form 10-K.
Table of Contents
Glossary of Crude Oil and Natural Gas Terms
The terms defined in this section may be used throughout this report:
“basin” A large natural depression on the earth’s surface in which sediments generally brought by water accumulate.
“Bbl” One stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids.
“Bcf” One billion cubic feet of natural gas.
“Boe” Barrels of crude oil equivalent, with six thousand cubic feet of natural gas being equivalent to one barrel of crude oil based on the average equivalent energy content of the two commodities.
“Btu” British thermal unit, which represents the amount of energy needed to heat one pound of water by one degree Fahrenheit and can be used to describe the energy content of fuels.
“completion” The process of treating a drilled well followed by the installation of permanent equipment for the production of crude oil and/or natural gas.
“conventional play” An area believed to be capable of producing crude oil and natural gas occurring in discrete accumulations in structural and stratigraphic traps.
“DD&A” Depreciation, depletion, amortization and accretion.
“de-risked” Refers to acreage and locations in which the Company believes the geological risks and uncertainties related to recovery of crude oil and natural gas have been reduced as a result of drilling operations to date. However, only a portion of such acreage and locations have been assigned proved undeveloped reserves and ultimate recovery of hydrocarbons from such acreage and locations remains subject to all risks of recovery applicable to other acreage.
“developed acreage” The number of acres allocated or assignable to productive wells or wells capable of production.
“development well” A well drilled within the proved area of a crude oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
“dry hole” Exploratory or development well that does not produce crude oil and/or natural gas in economically producible quantities.
“enhanced recovery” The recovery of crude oil and natural gas through the injection of liquids or gases into the reservoir, supplementing its natural energy. Enhanced recovery methods are sometimes applied when production slows due to depletion of the natural pressure.
“exploratory well” A well drilled to find crude oil or natural gas in an unproved area, to find a new reservoir in an existing field previously found to be productive of crude oil or natural gas in another reservoir, or to extend a known reservoir beyond the proved area.
“field” An area consisting of a single reservoir or multiple reservoirs all grouped on, or related to, the same individual geological structural feature or stratigraphic condition. The field name refers to the surface area, although it may refer to both the surface and the underground productive formations.
“formation” A layer of rock which has distinct characteristics that differs from nearby rock.
“fracture stimulation” A process involving the high pressure injection of water, sand and additives into rock formations to stimulate crude oil and natural gas production. Also may be referred to as hydraulic fracturing.
“gross acres” or “gross wells” Refers to the total acres or wells in which a working interest is owned.
“held by production” or “HBP” Refers to an oil and gas lease continued into effect into its secondary term for so long as a producing oil and/or gas well is located on any portion of the leased premises or lands pooled therewith.
“horizontal drilling” A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled horizontally within a specified interval.
“MBbl” One thousand barrels of crude oil, condensate or natural gas liquids.
“MBoe” One thousand Boe.
“Mcf” One thousand cubic feet of natural gas.
“MMBo” One million barrels of crude oil.
“MMBoe” One million Boe.
“MMBtu” One million British thermal units.
“MMcf” One million cubic feet of natural gas.
“net acres” or “net wells” Refers to the sum of the fractional working interests owned in gross acres or gross wells.
"Net crude oil and natural gas sales" Represents total crude oil and natural gas sales less total transportation expenses. Net crude oil and natural gas sales presented herein is a non-GAAP measure. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
"Net sales price" Represents the average net wellhead sales price received by the Company for its crude oil or natural gas sales after deducting transportation expenses. Net sales price is calculated by taking revenues less transportation expenses divided by sales volumes for a period, whether for crude oil or natural gas, as applicable. Net sales prices presented herein for 2018, 2019, and 2020 are non-GAAP measures. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of this measure.
“NYMEX” The New York Mercantile Exchange.
“pad drilling” or “pad development” Describes a well site layout which allows for drilling multiple wells from a single pad resulting in less environmental impact and lower per-well drilling and completion costs.
“play” A portion of the exploration and production cycle following the identification by geologists and geophysicists of areas with potential crude oil and natural gas reserves.
“productive well” A well found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
“prospect” A potential geological feature or formation which geologists and geophysicists believe may contain hydrocarbons. A prospect can be in various stages of evaluation, ranging from a prospect that has been fully evaluated and is ready to drill to a prospect that will require substantial additional seismic data processing and interpretation.
“proved reserves” The quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain.
“proved developed reserves” Reserves expected to be recovered through existing wells with existing equipment and operating methods.
“proved undeveloped reserves” or “PUD” Proved reserves expected to be recovered from new wells on undrilled acreage or from existing wells where a relatively major expenditure is required for completion.
“PV-10” When used with respect to crude oil and natural gas reserves, PV-10 represents the estimated future gross revenues to be generated from the production of proved reserves using a 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December, net of estimated production and future development and abandonment costs based on costs in effect at the determination date, before income taxes, and without giving effect to non-property-related expenses, discounted to a present value using an annual discount rate of 10% in accordance with the guidelines of the Securities and Exchange Commission (“SEC”). PV-10 is not a financial measure calculated in accordance with generally accepted accounting principles (“GAAP”) and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of the Company’s crude oil and natural gas properties. The Company and others in the industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific tax characteristics of such entities.
“reservoir” A porous and permeable underground formation containing a natural accumulation of producible crude oil and/or natural gas that is confined by impermeable rock or water barriers and is separate from other reservoirs.
“residue gas” Refers to gas that has been processed to remove natural gas liquids.
“resource play” Refers to an expansive contiguous geographical area with prospective crude oil and/or natural gas reserves that has the potential to be developed uniformly with repeatable commercial success due to advancements in horizontal drilling and completion technologies.
“royalty interest” Refers to the ownership of a percentage of the resources or revenues produced from a crude oil or natural gas property. A royalty interest owner does not bear exploration, development, or operating expenses associated with drilling and producing a crude oil or natural gas property.
“SCOOP” Refers to the South Central Oklahoma Oil Province, a term used to describe properties located in the Anadarko basin of Oklahoma in which we operate. Our SCOOP acreage extends across portions of Garvin, Grady, Stephens, Carter, McClain and Love counties of Oklahoma and has the potential to contain hydrocarbons from a variety of conventional and unconventional reservoirs overlying and underlying the Woodford formation.
“STACK” Refers to Sooner Trend Anadarko Canadian Kingfisher, a term used to describe a resource play located in the Anadarko Basin of Oklahoma characterized by stacked geologic formations with major targets in the Meramec, Osage and Woodford formations. A significant portion of our STACK acreage is located in over-pressured portions of Blaine, Dewey and Custer counties of Oklahoma.
“spacing” The distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 640-acre spacing) and is often established by regulatory agencies.
“Standardized Measure” Discounted future net cash flows estimated by applying the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January to December to the estimated future production of year-end proved reserves. Future cash inflows are reduced by estimated future production and development costs based on period-end costs to determine pre-tax net cash inflows. Future income taxes, if applicable, are computed by applying the statutory tax rate to the excess of pre-tax cash inflows over the tax basis in the crude oil and natural gas properties. Future net cash inflows after income taxes are discounted using a 10% annual discount rate.
“unconventional play” An area believed to be capable of producing crude oil and natural gas occurring in accumulations that are regionally extensive, but may lack readily apparent traps, seals and discrete hydrocarbon-water boundaries that typically define conventional reservoirs. These areas tend to have low permeability and may be closely associated with source rock, as is the case with oil and gas shale, tight oil and gas sands and coalbed methane, and generally require horizontal drilling, fracture stimulation treatments or other special recovery processes in order to achieve economic production.
“undeveloped acreage” Lease acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of crude oil and/or natural gas.
“unit” The joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement.
“well bore” The hole drilled by the bit that is equipped for crude oil or natural gas production on a completed well. Also called a well or borehole.
“working interest” The right granted to the lessee of a property to explore for and to produce and own crude oil, natural gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis.
Cautionary Statement for the Purpose of the “Safe Harbor” Provisions of the Private Securities Litigation Reform Act of 1995
This report and information incorporated by reference in this report include “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 and Section 21E of the Securities Exchange Act of 1934. All statements other than statements of historical fact, including, but not limited to, forecasts or expectations regarding the Company’s business and statements or information concerning the Company’s future operations, performance, financial condition, production and reserves, schedules, plans, timing of development, rates of return, budgets, costs, business strategy, objectives, and cash flows, included in this report are forward-looking statements. The words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “budget,” “target,” “plan,” “continue,” “potential,” “guidance,” “strategy” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words.
Forward-looking statements may include, but are not limited to, statements about:
•our business and financial plans;
•our future operations;
•our crude oil and natural gas reserves and related development plans;
•future crude oil, natural gas liquids, and natural gas prices and differentials;
•the timing and amount of future production of crude oil and natural gas and flaring activities;
•the amount, nature and timing of capital expenditures;
•estimated revenues, expenses and results of operations;
•drilling and completing of wells;
•shutting in of production and the resumption of production activities;
•marketing of crude oil and natural gas;
•transportation of crude oil, natural gas liquids, and natural gas to markets;
•property exploitation, property acquisitions and dispositions, or joint development opportunities;
•costs of exploiting and developing our properties and conducting other operations;
•our financial position, dividend payments, bond repurchases, or share repurchases;
•the impact of the COVID-19 (novel coronavirus) pandemic on economic conditions, the demand for crude oil, the Company's operations and the operations of its customers, suppliers, and service providers;
•our liquidity and access to capital;
•the impact of governmental policies, laws and regulations, as well as regulatory and legal proceedings involving us and of scheduled or potential regulatory or legal changes;
•our future operating and financial results;
•our future commodity or other hedging arrangements; and
•the ability and willingness of current or potential lenders, hedging contract counterparties, customers, and working interest owners to fulfill their obligations to us or to enter into transactions with us in the future on terms that are acceptable to us.
Forward-looking statements are based on the Company’s current expectations and assumptions about future events and currently available information as to the outcome and timing of future events. Although the Company believes these assumptions and expectations are reasonable, they are inherently subject to numerous business, economic, competitive, regulatory and other risks and uncertainties, most of which are difficult to predict and many of which are beyond the Company’s control. No assurance can be given that such expectations will be correct or achieved or that the assumptions are accurate or will not change over time. The risks and uncertainties that may affect the operations, performance and results of the business and forward-looking statements include, but are not limited to, those risk factors and other cautionary statements described under Part I, Item 1A. Risk Factors and elsewhere in this report, registration statements we file from time to time with the Securities and Exchange Commission, and other announcements we make from time to time.
Many of the foregoing risks and uncertainties have been, and may further be, exacerbated by the COVID-19 pandemic and any consequent worsening of the global economic environment. New factors emerge from time to time, and it is not possible for us to predict all such factors. Readers are cautioned not to place undue reliance on forward-looking statements, which speak only as of the date on which such statement is made. Should one or more of the risks or uncertainties described in this report occur, or should underlying assumptions prove incorrect, the Company’s actual results and plans could differ materially from those
expressed in any forward-looking statements. All forward-looking statements are expressly qualified in their entirety by this cautionary statement.
Except as expressly stated above or otherwise required by applicable law, the Company undertakes no obligation to publicly correct or update any forward-looking statement whether as a result of new information, future events or circumstances after the date of this report, or otherwise.
You should read this entire report carefully, including the risks described under Part I, Item 1A. Risk Factors and our consolidated financial statements and the notes to those consolidated financial statements included elsewhere in this report. Unless the context otherwise requires, references in this report to “Continental Resources,” “Continental,” “we,” “us,” “our,” “ours” or “the Company” refer to Continental Resources, Inc. and its subsidiaries.
Item 1. Business
We are an independent crude oil and natural gas company formed in 1967 engaged in the exploration, development, and production of crude oil and natural gas in the North, South and East regions of the United States. Additionally, we pursue the acquisition and management of perpetually owned minerals located in our key operating areas. The North region consists of properties north of Kansas and west of the Mississippi River and includes North Dakota Bakken, Montana Bakken, and the Red River units. The South region includes all properties south of Nebraska and west of the Mississippi River including various plays in the SCOOP and STACK areas of Oklahoma. The East region is primarily comprised of undeveloped leasehold acreage east of the Mississippi River with no significant drilling or production operations.
Our operations in the North region comprised 55% of our crude oil and natural gas production and 65% of our crude oil and natural gas revenues for the year ended December 31, 2020. The Company’s principal producing properties in the North region are located in the Bakken field of North Dakota and Montana. Approximately 48% of our proved reserves as of December 31, 2020 are located in the North region. Our operations in the South region comprised 45% of our crude oil and natural gas production, 35% of our crude oil and natural gas revenues, and 52% of our proved reserves as of and for the year ended December 31, 2020.
We focus our activities in large new or developing crude oil and natural gas plays that provide us the opportunity to acquire undeveloped acreage positions for future drilling operations. We have been successful in targeting large repeatable resource plays where three dimensional seismic, horizontal drilling, geosteering technologies, advanced completion technologies (e.g., fracture stimulation), pad/row development, and enhanced recovery technologies allow us to develop and produce crude oil and natural gas reserves from unconventional formations. As a result of these efforts, we have grown substantially through the drill bit.
As of December 31, 2020, our proved reserves were 1,104 MMBoe, with proved developed reserves representing 627 MMBoe, or 57%, of our total proved reserves. The standardized measure of our discounted future net cash flows totaled $4.65 billion at December 31, 2020. For 2020, we generated crude oil and natural gas revenues of $2.56 billion and operating cash flows of $1.42 billion. Crude oil accounted for 53% of our total production and 86% of our crude oil and natural gas revenues for 2020. Our total production averaged 300,090 Boe per day for 2020, a decrease of 12% compared to 2019.
The table below summarizes our total proved reserves, PV-10 (non-GAAP) and net producing wells as of December 31, 2020, average daily production for the quarter ended December 31, 2020 and the reserve-to-production index in our principal operating areas. The PV-10 values shown below are not intended to represent the fair market value of our crude oil and natural gas properties. There are numerous uncertainties inherent in estimating quantities of crude oil and natural gas reserves. See Part I, Item 1A. Risk Factors and “Critical Accounting Policies and Estimates” in Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations of this report for further discussion of uncertainties inherent in the reserve estimates.
| ||December 31, 2020||Average daily|
(Boe per day)
|North Dakota Bakken||483,238 ||43.8 ||%||$||2,235 ||1,631 ||177,802 ||52.4 ||%||7.4 |
|Montana Bakken||25,754 ||2.3 ||%||128 ||254 ||5,339 ||1.6 ||%||13.2 |
|Red River units|
|Cedar Hills||17,670 ||1.6 ||%||142 ||130 ||5,323 ||1.6 ||%||9.1 |
|Other Red River units||932 ||0.1 ||%||7 ||116 ||1,467 ||0.4 ||%||1.7 |
|SCOOP||478,196 ||43.3 ||%||2,139 ||463 ||107,060 ||31.6 ||%||12.2 |
|STACK||97,967 ||8.9 ||%||241 ||299 ||42,281 ||12.4 ||%||6.3 |
|Other||5 ||— ||%||1 ||2 ||35 ||— ||%||0.4 |
|Total||1,103,762 ||100.0 ||%||$||4,893 ||2,895 ||339,307 ||100.0 ||%||8.9 |
(1)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $239 million. Neither PV-10 nor Standardized Measure represents an estimate of the fair market value of our crude oil and natural gas properties. We and others in the crude oil and natural gas industry use PV-10 as a measure to compare the relative size and value of proved reserves held by companies without regard to the specific income tax characteristics of such entities. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.
(2)The Annualized Reserve/Production Index is the number of years that estimated proved reserves would last assuming current production continued at the same rate. This index is calculated by dividing annualized fourth quarter 2020 production into estimated proved reserve volumes as of December 31, 2020.
Business Environment and Outlook
In March 2020, the World Health Organization declared a global pandemic related to the proliferation of COVID-19 (novel coronavirus). The ensuing economic turmoil caused by the pandemic resulted in a significant reduction in global and domestic demand for crude oil due to, among other things, changes in consumer behavior and restrictions implemented by governments to mitigate the pandemic. This demand destruction contributed to an unprecedented decline in crude oil prices, with West Texas Intermediate benchmark prices reaching all-time lows in April 2020. In response to the significant reduction in crude oil prices, we began voluntarily curtailing our production in April 2020 and ultimately curtailed approximately 55% of our operated crude oil production and associated natural gas in the 2020 second quarter. Additionally, in light of the challenges facing our business and industry, we implemented cost saving initiatives and significantly reduced our operated rig and completion crew counts in order to preserve our assets and better align our capital spending with expected available cash flows, resulting in a $1.5 billion, or 56%, decrease in our non-acquisition capital spending in 2020 compared to 2019. These actions, coupled with historically low crude oil prices, resulted in a material reduction in our production, revenues, and cash flows in 2020 compared to 2019.
Crude oil prices began to stabilize in mid-2020 and generally improved in the second half of 2020 in response to the gradual lifting of COVID-19 restrictions, the resumption of economic activity, and the resulting increase in crude oil demand. In July 2020 we began to gradually restore our curtailed production and subsequently brought our remaining curtailed production back online in September 2020. As a result of our resumed production, coupled with strategic well completion activities in late 2020, our total average production improved to 339,307 Boe per day for the 2020 fourth quarter, representing a 14% increase compared to the third quarter of 2020, yet still remaining 7% lower than the fourth quarter of 2019.
Despite the gradual improvement in crude oil prices in the second half of 2020, we continued our commitment to operating in a disciplined, capital efficient manner. Improved revenues from higher commodity prices coupled with our tempered spending resulted in the generation of cash flows in excess of operating and capital needs in the second half of 2020 that allowed for a $210 million net reduction in our total debt at December 31, 2020 compared to June 30, 2020. Additionally, despite production curtailments during the year, we continued to drive our per-unit production expenses lower to $3.27 per Boe for 2020 compared to $3.58 per Boe for 2019.
We remain committed to the responsible stewardship of our assets and continue to focus on maximizing cash flows, further reducing debt, delivering low-cost capital efficient operations, and generating shareholder value. The depth and quality of our asset base, the commodity optionality provided by our significant amount of acreage held by production, and our financial strength allow us to be adaptable in a variety of price environments. We remain flexible as we monitor and adapt to market conditions.
For 2021, our primary business strategies will focus on generating shareholder value by:
•Continuing to exercise capital and operational discipline to maximize cash flow generation;
•Reducing outstanding debt;
•Capitalizing on commodity optionality afforded to us by our crude oil and natural gas assets; and
•Maintaining low-cost operations.
Our Business Strategies
Despite volatility and uncertainty in commodity prices, our business strategies continue to be focused on generating shareholder value by finding and developing crude oil and natural gas reserves at low costs and attractive rates of return. The principal elements of this strategy include:
Growing and sustaining our premier portfolio of assets in a disciplined manner to maximize cash flow generation. We hold a portfolio of leasehold acreage, drilling opportunities, uncompleted wells, perpetually owned minerals, and water infrastructure assets in certain premier U.S. resource plays with varying access to crude oil, natural gas, and natural gas liquids. Our capital programs are designed to allocate investments to projects that provide the best opportunities to generate cash flows in excess of operating and capital requirements, capitalize on movements in strip pricing between crude oil and natural gas, convert our undeveloped acreage to acreage held by production, harvest our inventory of uncompleted wells, and improve hydrocarbon recoveries and rates of return on capital employed. We are strongly aligned with shareholders and our strategic vision is predicated on our desire to generate shareholder value through various means.
Reducing outstanding debt. Maintaining a strong balance sheet, ample liquidity, and financial flexibility are key components of our business strategy. A cornerstone of our 2021 plan is to maximize cash flow generation to pay down debt. In 2021 and beyond we will continue our focus on paying down debt and preserving financial flexibility and ample liquidity as we manage the risks facing our industry.
Capitalizing on commodity optionality afforded to us by our crude oil and natural gas assets. We have a deep inventory of both oil and gas assets across the Bakken and Oklahoma that allow us to be responsive to, and benefit from, changes in oil and gas commodity price fundamentals. This commodity optionality provides an inherent advantage to Continental. Not only do we have the ability to shift capital between our Bakken and Oklahoma assets, but within Oklahoma we have the ability to shift capital between oil-weighted or gas-weighted projects depending on which commodity has a stronger price outlook. We also have direct access to multiple premium markets from our Oklahoma assets, which allow us to pursue either oil or gas markets as prices and fundamentals warrant. For 2021, we plan to remain flexible and responsive with our drilling and completion programs to capitalize on relative movements in oil and gas prices.
Maintaining low-cost operations. Our culture is defined by our low cost operations and in 2020 we again delivered low cost industry leadership despite the challenges facing our business. We continue to manage our business in the volatile commodity price environment by focusing on improving operating and capital efficiencies and reducing costs by exploiting technical innovations, pad and row development opportunities, and other means. Our key operating areas are characterized by large acreage positions in select unconventional resource plays with multiple stacked geologic formations that provide repeatable drilling opportunities and resource potential. We operate a significant portion of our wells and leasehold acreage and believe the concentration of our operated assets allows us to leverage our technical expertise and manage the development of our properties to enhance operating efficiencies and economies of scale. Our operational excellence has allowed us to achieve and maintain enviable low-cost operations.
Our Business Strengths
We have a number of strengths to allow us to successfully execute our business strategies, including the following:
Large acreage inventory with access to both crude oil and natural gas resources. We held approximately 359,300 net undeveloped acres and 1.23 million net developed acres under lease as of December 31, 2020 concentrated in certain premier U.S. resource plays that provide optionality and access to crude oil, natural gas, and natural gas liquids. We are among the largest leaseholders in the Bakken, SCOOP and STACK plays. Being an early entrant in these plays has allowed us to capture significant acreage positions in core parts of the plays.
Expertise with pad and row development, horizontal drilling, and optimized completion methods. We have substantial experience with horizontal drilling and optimized completion methods and continue to be among industry leaders in the use of new drilling and completion technologies. We continue to improve drilling and completion efficiencies through the use of multi-well pad and row development strategies. Further, we are among industry leaders in drilling long lateral lengths. We have also been among industry leaders in testing and utilizing optimized completion technologies involving various combinations of fluid types, proppant types and volumes, and stimulation stage spacing to determine optimal methods for improving recoveries and rates of return. We continually refine our drilling and completion techniques in an effort to deliver improved results across our properties.
Control operations over a substantial portion of our assets and investments. As of December 31, 2020, we operated properties comprising 88% of our total proved reserves. By controlling a significant portion of our operations, we are able to more effectively manage the cost and timing of exploration and development of our properties, including the drilling and completion methods used. Additionally, we capitalize on our geologic knowledge and land expertise to strategically acquire minerals in areas of future growth, thereby allowing us to enhance cash flows and project economics through the alignment of mineral ownership with our drilling schedule. Further, we continue to grow our significant portfolio of water gathering, recycling, and disposal infrastructure assets which allow for uninterrupted flow back and recycling capabilities, supports timely completion activities, and generates additional service revenues and cash flows. Our strategies for growing our mineral ownership portfolio and water infrastructure assets serve as additional avenues to generate shareholder value.
Experienced Management Team. Our senior management team has extensive expertise in the oil and gas industry and with operating in challenging commodity price environments. Our Executive Chairman, Harold G. Hamm, began his career in the oil and gas industry in 1967. Our 8 executive officers have an average of 41 years of oil and gas industry experience.
Financial Position and Liquidity. We have a credit facility with lender commitments totaling $1.5 billion that matures in April 2023. We had approximately $1.33 billion of borrowing availability on our credit facility at December 31, 2020 after considering outstanding borrowings and letters of credit. Our credit facility is unsecured and does not have a borrowing base requirement that is subject to periodic redetermination based on changes in commodity prices and proved reserves. Additionally, downgrades or other negative rating actions with respect to our credit rating do not trigger a reduction in our current credit facility commitments, nor do such actions trigger a security requirement or change in covenants.
Crude Oil and Natural Gas Operations
Proved reserves are those quantities of crude oil and natural gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expire, unless evidence indicates renewal is reasonably certain. In connection with the estimation of proved reserves, the term “reasonable certainty” implies a high degree of confidence the quantities of crude oil and/or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, our internal reserve engineers and Ryder Scott Company, L.P (“Ryder Scott”), our independent reserve engineers, employed technologies demonstrated to yield results with consistency and repeatability. The technologies and economic data used in the estimation of our proved reserves include, but are not limited to, well logs, geologic maps including isopach and structure maps, analogy and statistical analysis, and available downhole, production, seismic, and well test data.
The table below sets forth estimated proved crude oil and natural gas reserves information by reserve category as of December 31, 2020. Proved reserves attributable to noncontrolling interests are not material relative to our consolidated reserves and are not separately presented herein. The standardized measure of our discounted future net cash flows totaled approximately $4.65 billion at December 31, 2020. Our reserve estimates as of December 31, 2020 are based primarily on a reserve report prepared by Ryder Scott. In preparing its report, Ryder Scott evaluated properties representing approximately 93% of our PV-10 and 95% of our total proved reserves as of December 31, 2020. Our internal technical staff evaluated the remaining properties. A copy of Ryder Scott’s summary report is included as an exhibit to this Annual Report on Form 10-K.
Our estimated proved reserves and related future net revenues, Standardized Measure and PV-10 at December 31, 2020 were determined using the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the period of January 2020 through December 2020, without giving effect to derivative transactions, and were held constant throughout the lives of the properties. These prices were $39.57 per Bbl for crude oil and $1.99 per MMBtu for natural gas ($34.34 per Bbl for crude oil and $1.17 per Mcf for natural gas adjusted for location and quality differentials). These average prices are significantly lower than 2019 levels, which resulted in significant downward price-related revisions to proved reserves in 2020. Additionally, in 2020 we reduced the scope of our future drilling programs in response to the reduction in consumer demand and lower prices prompted by the COVID-19 pandemic, which resulted in the removal of PUD reserves no longer scheduled to
be drilled within five years of initial booking. These revisions are further discussed below and contributed to significant decreases in our proved reserves, Standardized Measure, and PV-10 in 2020 compared to 2019.
The following table summarizes our estimated proved reserves by commodity and reserve classification as of December 31, 2020.
|Proved developed producing||271,904 ||2,023,293 ||609,119 ||$||3,962.5 |
|Proved developed non-producing||10,002 ||49,718 ||18,288 ||110.8 |
|Proved undeveloped||215,069 ||1,567,713 ||476,355 ||819.4 |
|Total proved reserves||496,975 ||3,640,724 ||1,103,762 ||$||4,892.7 |
|Standardized Measure (1)||$||4,653.6 |
(1)PV-10 is a non-GAAP financial measure and generally differs from Standardized Measure, the most directly comparable GAAP financial measure, because it does not include the effects of income taxes on future net revenues of approximately $239 million. See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for further discussion.
The following table provides additional information regarding our estimated proved crude oil and natural gas reserves by region as of December 31, 2020.
| ||Proved Developed||Proved Undeveloped|
| ||Crude Oil|
|North Dakota Bakken||170,498 ||550,159 ||262,191 ||159,674 ||368,239 ||221,047 |
|Montana Bakken||12,114 ||25,573 ||16,377 ||7,330 ||12,281 ||9,377 |
|Red River units|
|Cedar Hills||17,670 ||— ||17,670 ||— ||— ||— |
|Other Red River units||932 ||— ||932 ||— ||— ||— |
|SCOOP||69,955 ||1,073,955 ||248,947 ||46,263 ||1,097,920 ||229,249 |
|STACK||10,732 ||423,320 ||81,285 ||1,802 ||89,273 ||16,682 |
|Other||5 ||4 ||5 ||— ||— ||— |
|Total||281,906 ||2,073,011 ||627,407 ||215,069 ||1,567,713 ||476,355 |
The following table provides information regarding changes in total estimated proved reserves for the periods presented.
| ||Year Ended December 31,|
|Proved reserves at beginning of year||1,619,265 ||1,522,365 ||1,330,995 |
|Revisions of previous estimates||(504,874)||(148,848)||(269,253)|
|Extensions, discoveries and other additions||91,387 ||365,034 ||565,030 |
|Sales of minerals in place||— ||(1,840)||(8,011)|
|Purchases of minerals in place||7,817 ||6,798 ||12,443 |
|Proved reserves at end of year||1,103,762 ||1,619,265 ||1,522,365 |
Revisions of previous estimates. Revisions for 2020 are comprised of (i) the removal of 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of our future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic and our resulting allocation of capital to areas providing the best opportunities to improve efficiencies,
recoveries, and rates of return, (ii) downward revisions of 29 MMBo and 172 Bcf (totaling 58 MMBoe) from the removal of PUD reserves due to changes in economics, performance, and other factors, (iii) downward price revisions of 214 MMBo and 1,043 Bcf (totaling 388 MMBoe) due to the significant decrease in average crude oil and natural gas prices in 2020 compared to 2019 resulting from the economic turmoil caused by the COVID-19 pandemic and other factors, and (iv) net upward revisions of 43 MMBo and 31 Bcf (totaling 48 MMBoe) due to changes in ownership interests, operating costs, anticipated production, and other factors.
Extensions, discoveries and other additions. Extensions, discoveries and other additions for each of the three years reflected in the table above were due to successful drilling and completion activities and continual refinement of our drilling programs in the Bakken, SCOOP, and STACK plays. Proved reserve additions in the Bakken totaled 41 MMBoe, 160 MMBoe, and 251 MMBoe for 2020, 2019, and 2018, respectively, while reserve additions in SCOOP totaled 49 MMBoe, 186 MMBoe, and 186 MMBoe for 2020, 2019, and 2018, respectively. Additionally, reserve additions in STACK totaled 1 MMBoe, 19 MMBoe, and 128 MMBoe in 2020, 2019, and 2018, respectively. See the subsequent section titled Summary of Crude Oil and Natural Gas Properties and Projects for a discussion of our 2020 drilling activities.
Sales of minerals in place. We had no individually significant dispositions of proved reserves in the past three years.
Purchases of minerals in place. We had no individually significant acquisitions of proved reserves in the past three years.
Proved Undeveloped Reserves
All of our PUD reserves at December 31, 2020 are located in the Bakken, SCOOP, and STACK plays, our most active development areas, with those plays comprising 48%, 48%, and 4%, respectively, of our total PUD reserves at year-end 2020. The following table provides information regarding changes in our PUD reserves for the year ended December 31, 2020. Our PUD reserves at December 31, 2020 include 98 MMBoe of reserves associated with wells where drilling has occurred but the wells have not been completed or are completed but not producing ("DUC wells"). Our DUC wells are classified as PUD reserves when relatively major expenditures are required to complete and produce from the wells.
| ||Crude Oil|
|Proved undeveloped reserves at December 31, 2019||423,782 ||2,928,354 ||911,841 |
|Revisions of previous estimates||(210,569)||(1,326,177)||(431,599)|
|Extensions and discoveries||37,605 ||271,611 ||82,874 |
|Sales of minerals in place||— ||— ||— |
|Purchases of minerals in place||496 ||5,363 ||1,390 |
|Conversion to proved developed reserves||(36,245)||(311,438)||(88,151)|
|Proved undeveloped reserves at December 31, 2020||215,069 ||1,567,713 ||476,355 |
Revisions of previous estimates. As previously discussed, in 2020 we removed 50 MMBo and 345 Bcf (totaling 107 MMBoe) of PUD reserves no longer scheduled to be drilled within five years of initial booking due to a reduction in the scope of our future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic. Of these removals, 31 MMBo and 90 Bcf (totaling 46 MMBoe) was related to Bakken properties, 18 MMBo and 224 Bcf (totaling 56 MMBoe) was related to SCOOP properties, and 31 Bcf (5 MMBoe) was related to STACK properties. Additionally, changes in economics, performance, and other factors resulted in downward PUD reserve revisions of 29 MMBo and 172 Bcf (totaling 58 MMBoe) in 2020. The significant decreases in average crude oil and natural gas prices in 2020 resulting from the COVID-19 pandemic and other factors resulted in downward price revisions of 145 MMBo and 813 Bcf (totaling 280 MMBoe). Finally, changes in ownership interests, operating costs, anticipated production, and other factors resulted in net upward revisions for PUD reserves of 13 MMBo and 6 Bcf (totaling 14 MMBoe) in 2020.
Extensions and discoveries. Extensions and discoveries were primarily due to successful drilling activities and continual refinement of our drilling programs in the Bakken and SCOOP plays. PUD reserve additions in the Bakken totaled 27 MMBo and 56 Bcf (totaling 36 MMBoe) in 2020, while SCOOP PUD reserve additions totaled 11 MMBo and 216 Bcf (totaling 47 MMBoe).
Sales of minerals in place. We had no individually significant dispositions of PUD reserves in 2020.
Purchases of minerals in place. We had no individually significant acquisitions of PUD reserves in 2020.
Conversion to proved developed reserves. In 2020, we developed approximately 12% of our PUD locations and 10% of our PUD reserves booked as of December 31, 2019 through the drilling and completion of 328 gross (149 net) development wells at an aggregate capital cost of approximately $439 million incurred in 2020.
Our original capital budget for 2020 was $2.65 billion, which was reduced to $1.2 billion in March 2020 in response to the sudden, unprecedented decrease in crude oil prices resulting from the COVID-19 pandemic and other factors. Due to economic uncertainty from the pandemic, we significantly reduced our drilling and completion activities from previously planned levels in order to preserve financial flexibility and better align our spending with expected available cash flows. These factors adversely impacted our conversion of PUD reserves to proved developed reserves in 2020.
Development plans. We have acquired substantial leasehold positions in the Bakken, SCOOP and STACK plays. Our drilling programs to date in those areas have focused on proving our undeveloped leasehold acreage through strategic drilling, thereby increasing the amount of leasehold acreage in the secondary term of the lease with no further drilling obligations (i.e., categorized as held by production) and resulting in a reduced amount of leasehold acreage in the primary term of the lease. While we may opportunistically drill strategic exploratory wells, a substantial portion of our future capital expenditures will be focused on developing our PUD locations, including our drilled but not completed locations. Our inventory of DUC wells classified as PUDs total 316 gross (121 net) operated and non-operated locations at December 31, 2020 and represent 20% of our PUD reserves at that date. The costs to drill our uncompleted wells were incurred prior to December 31, 2020 and only the remaining completion costs are included in future development plans.
Estimated future development costs relating to the development of PUD reserves are projected to be approximately $732 million in 2021, $734 million in 2022, $889 million in 2023, $1.1 billion in 2024, and $448 million in 2025. These capital expenditure projections have been established based on an expectation of drilling and completion costs, available cash flows, borrowing capacity, and the commodity price environment in effect at the time of preparing our reserve estimates and may be adjusted as market conditions evolve. Development of our existing PUD reserves at December 31, 2020 is expected to occur within five years of the date of initial booking of the PUDs. PUD reserves not expected to be drilled within five years of initial booking because of changes in business strategy or for other reasons have been removed from our reserves at December 31, 2020. We had no PUD reserves at December 31, 2020 that remain undeveloped beyond five years from the date of initial booking.
Qualifications of Technical Persons and Internal Controls Over Reserves Estimation Process
Ryder Scott, our independent reserves evaluation consulting firm, estimated, in accordance with generally accepted petroleum engineering and evaluation principles and definitions and guidelines established by the SEC, 93% of our PV-10 and 95% of our total proved reserves as of December 31, 2020 included in this Form 10-K. The Ryder Scott technical personnel responsible for preparing the reserve estimates presented herein meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Refer to Exhibit 99 included with this Form 10-K for further discussion of the qualifications of Ryder Scott personnel.
We maintain an internal staff of petroleum engineers and geoscience professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to Ryder Scott in their reserves estimation process. Our technical team is in contact regularly with representatives of Ryder Scott to review properties and discuss methods and assumptions used in Ryder Scott’s preparation of the year-end reserves estimates. Proved reserves information is reviewed by our Audit Committee with representatives of Ryder Scott and by our internal technical staff before the information is filed with the SEC on Form 10-K. Additionally, certain members of our senior management review and approve the Ryder Scott reserves report and on a semi-annual basis review any internal proved reserves estimates.
Our Vice President—Corporate Reserves is the technical person primarily responsible for overseeing the preparation of our reserve estimates. He has a Bachelor of Science degree in Petroleum Engineering, an MBA in Finance and 36 years of industry experience with positions of increasing responsibility in operations, acquisitions, engineering and evaluations. He has worked in the area of reserves and reservoir engineering most of his career and is a member of the Society of Petroleum Engineers. The Vice President—Corporate Reserves reports directly to our Vice Chairman of Strategic Growth Initiatives. The reserves estimates are reviewed and approved by certain members of the Company's executive management.
Proved Reserves, Standardized Measure, and PV-10 Sensitivities
Our year-end 2020 proved reserves, Standardized Measure, and PV-10 estimates were prepared using 2020 average first-day-of-the-month prices of $39.57 per Bbl for crude oil and $1.99 per MMBtu for natural gas ($34.34 per Bbl for crude oil and $1.17 per Mcf for natural gas adjusted for location and quality differentials). Actual future prices may be materially higher or lower than those used in our year-end estimates.
Provided below are sensitivities illustrating the potential impact on our estimated proved reserves, Standardized Measure, and PV-10 at December 31, 2020 under different commodity price scenarios for crude oil and natural gas. In these sensitivities, all factors other than the commodity price assumption have been held constant for each well. These sensitivities do not take into account a potential increase in our drilling activities and associated booking of additional proved reserves that may occur at higher commodity prices and there is no assurance the outcomes reflected below will be realized.
The crude oil price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under certain crude oil price scenarios, with natural gas prices being held constant at the 2020 average first-day-of-the-month price of $1.99 per MMBtu.
The natural gas price sensitivities provided below show the impact on proved reserves, Standardized Measure, and PV-10 under certain natural gas price scenarios, with crude oil prices being held constant at the 2020 average first-day-of-the-month price of $39.57 per Bbl.
Developed and Undeveloped Acreage
The following table presents our total gross and net developed and undeveloped acres by region as of December 31, 2020:
| ||Developed acres||Undeveloped acres||Total|
|North Dakota Bakken||949,852 ||563,260 ||105,095 ||61,248 ||1,054,947 ||624,508 |
|Montana Bakken||170,412 ||136,153 ||33,795 ||25,789 ||204,207 ||161,942 |
|Red River units||155,249 ||138,064 ||19,455 ||10,112 ||174,704 ||148,176 |
|Other||80,326 ||54,095 ||29,569 ||25,725 ||109,895 ||79,820 |
|SCOOP||276,618 ||166,327 ||183,840 ||107,459 ||460,458 ||273,786 |
|STACK||265,736 ||146,078 ||88,139 ||45,489 ||353,875 ||191,567 |
|Other||34,247 ||20,790 ||28,940 ||12,364 ||63,187 ||33,154 |
|East Region||734 ||670 ||77,547 ||71,159 ||78,281 ||71,829 |
|Total||1,933,174 ||1,225,437 ||566,380 ||359,345 ||2,499,554 ||1,584,782 |
The following table sets forth the number of gross and net undeveloped acres as of December 31, 2020 scheduled to expire over the next three years by region unless production is established within the spacing units covering the acreage prior to the expiration dates or the leases are renewed.
|North Dakota Bakken||34,287 ||23,193 ||31,849 ||19,034 ||4,160 ||2,143 |
|Montana Bakken||1,480 ||1,480 ||12,182 ||10,311 ||5,697 ||5,580 |
|Other||— ||— ||— ||— ||17,847 ||17,847 |
|SCOOP||36,475 ||16,265 ||35,631 ||22,773 ||26,068 ||12,927 |
|STACK||31,465 ||19,241 ||11,541 ||7,696 ||4,259 ||3,114 |
|Other||4,889 ||744 ||8,987 ||6,063 ||2,942 ||2,592 |
|East Region||969 ||370 ||4,856 ||3,732 ||5,968 ||5,272 |
|Total||109,565 ||61,293 ||105,046 ||69,609 ||66,941 ||49,475 |
During the three years ended December 31, 2020, we participated in the drilling and completion of exploratory and development wells as set forth in the table below. As previously discussed, we significantly reduced our drilling and completion activities in 2020 in response to reduced crude oil prices, which resulted in a significant decrease in the number of wells completed during 2020 compared to prior years.
|Crude oil||1 ||— ||2 ||1.6 ||4 ||1.0 |
|Natural gas||1 ||— ||4 ||1.8 ||9 ||4.6 |
|Dry holes||1 ||0.9 ||— ||— ||— ||— |
|Total exploratory wells||3 ||0.9 ||6 ||3.4 ||13 ||5.6 |
|Crude oil||300 ||115.5 ||615 ||222.9 ||636 ||213.7 |
|Natural gas||31 ||15.9 ||68 ||9.7 ||151 ||39.1 |
|Dry holes||— ||— ||— ||— ||— ||— |
|Total development wells||331 ||131.4 ||683 ||232.6 ||787 ||252.8 |
|Total wells||334 ||132.3 ||689 ||236.0 ||800 ||258.4 |
As of December 31, 2020, there were 459 gross (156 net) operated and non-operated wells that have been spud and are in the process of drilling, completing or waiting on completion.
Summary of Crude Oil and Natural Gas Properties and Projects
In the following discussion, we review our budgeted number of wells and capital expenditures for 2021 in our key operating areas. Our 2021 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. Our drilling and completion activities and the actual amount and timing of our capital expenditures may differ materially from our budget as a result of, among other things, available cash flows, unbudgeted acquisitions, actual drilling and completion results, the availability of drilling and completion rigs and other services and equipment, the availability of transportation and processing capacity, changes in commodity prices, and regulatory, technological and competitive developments. We monitor our capital spending closely based on actual and projected cash flows and may scale back our spending should commodity prices decrease from current levels. Conversely, an increase in commodity prices from current levels could result in increased capital expenditures.
The following table provides information regarding well counts and budgeted capital expenditures for 2021.
| ||2021 Plan|
| ||Gross wells (1)||Net wells (1)||Capital expenditures |
(in millions) (2)
|North Region||229 ||94 ||$||732 |
|South Region||120 ||57 ||380 |
|Total exploration and development||349 ||151 ||$||1,112 |
|Mineral acquisitions attributable to Continental (3)||13 |
|Capital facilities, workovers, water infrastructure, and other||186 |
|2021 capital budget attributable to Continental||$||1,400 |
|Mineral acquisitions attributable to Franco-Nevada (3)||52 |
|Total 2021 capital budget||$||1,452 |
(1) Represents operated and non-operated wells expected to have first production in 2021.
(2) Represents total capital expenditures for operated and non-operated wells expected to have first production in 2021 and wells spud that will be in the process of drilling, completing or waiting on completion as of year-end 2021. Amounts exclude our pending acquisition of properties in the Powder River Basin of Wyoming for $215 million as discussed in Part II, Item 8. Notes to Consolidated Financial Statements—Note 12. Commitments and Contingencies.
(3) Represents planned spending for mineral acquisitions by The Mineral Resources Company II, LLC ("TMRC II") under our relationship with Franco-Nevada Corporation described in Part II, Item 8. Notes to Consolidated Financial Statements—Note 16. Noncontrolling Interests. Continental holds a controlling financial interest in TMRC II and therefore consolidates the financial results and capital expenditures of the entity. With a carry structure in place, Continental will fund 20% of 2021 planned spending, or $13 million, and Franco-Nevada will fund the remaining 80%, or $52 million.
Our properties in the North region represented 48% of our total proved reserves as of December 31, 2020 and 56% of our average daily Boe production for the fourth quarter of 2020. Our principal producing properties in the North region are located in the Bakken field.
The Bakken field of North Dakota and Montana is one of the largest crude oil resource plays in the United States. We are a leading producer, leasehold owner and operator in the Bakken. As of December 31, 2020, we controlled one of the largest leasehold positions in the Bakken with approximately 1.3 million gross (786,500 net) acres under lease.
Our total Bakken production averaged 183,141 Boe per day for the fourth quarter of 2020, down 6% from the 2019 fourth quarter. For the year ended December 31, 2020, our average daily Bakken production decreased 19% compared to 2019, reflecting our reduction in drilling and completion activities and the impact of voluntary production curtailments during the year. In 2020, we participated in the drilling and completion of 188 gross (77 net) wells in the Bakken compared to 379 gross (124 net) wells in 2019. Our 2020 activities in the Bakken focused on ongoing multi-zone unit development in core areas of the play.
Our Bakken properties represented 46% of our total proved reserves at December 31, 2020 and 54% of our average daily Boe production for the 2020 fourth quarter. Our total proved Bakken field reserves as of December 31, 2020 were 509 MMBoe, a decrease of 39% compared to December 31, 2019 primarily due to downward reserve revisions prompted by significantly reduced commodity prices and resulting changes in drilling plans. Our inventory of proved undeveloped drilling locations in the Bakken totaled 849 gross (404 net) wells as of December 31, 2020.
For 2021, our budget for exploration and development capital expenditures in the North region is $732 million. In 2021, we expect to have first production on 229 gross (94 net) operated and non-operated wells in the North region. We plan to average approximately seven operated rigs and three well completion crews in the North region in 2021. Our 2021 drilling and completion activities in the Bakken will continue to focus on multi-zone unit development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, improve recoveries and rates of return, and maximize cash flows.
Our properties in the South region represented 52% of our total proved reserves as of December 31, 2020 and 44% of our average daily Boe production for the fourth quarter of 2020. Our principal producing properties in the South region are located in the SCOOP and STACK areas of Oklahoma.
The SCOOP play extends across Garvin, Grady, Stephens, Carter, McClain and Love counties in Oklahoma and contains crude oil and condensate-rich fairways as delineated by numerous industry wells. We are a leading producer, leasehold owner and operator in the SCOOP play. As of December 31, 2020, we controlled one of the largest leasehold positions in SCOOP with approximately 460,500 gross (273,800 net) acres under lease.
SCOOP represented 43% of our total proved reserves as of December 31, 2020 and 32% of our average daily Boe production for the fourth quarter of 2020. Production in SCOOP averaged 107,060 Boe per day during the fourth quarter of 2020, down 4% compared to the 2019 fourth quarter. For the year ended December 31, 2020, average daily production in SCOOP increased 16% compared to 2019, reflecting additional drilling and completion activities in our Project SpringBoard which exceeded the impact of production curtailments in the play during the year. We participated in the drilling and completion of 123 gross (46 net) wells in SCOOP during 2020 compared to 207 gross (93 net) wells in 2019. Our total proved SCOOP field reserves as of December 31, 2020 were 478 MMBoe, a decrease of 17% compared to December 31, 2019 primarily due to downward reserve revisions prompted by significantly reduced commodity prices and resulting changes in drilling plans. Our inventory of proved undeveloped drilling locations in SCOOP totaled 262 gross (164 net) wells as of December 31, 2020.
The STACK play is located in the Anadarko Basin of Oklahoma and is characterized by stacked geologic formations with major targets in the Meramec, Osage, and Woodford formations. As of December 31, 2020, we controlled one of the largest leasehold positions in STACK with approximately 353,900 gross (191,600 net) acres under lease.
Our STACK properties represented 9% of our total proved reserves as of December 31, 2020 and 12% of our average daily Boe production for the fourth quarter of 2020. Production in STACK averaged 42,281 Boe per day during the fourth quarter of 2020, down 18% from the 2019 fourth quarter. For the year ended December 31, 2020, average daily production in STACK decreased 30% compared to 2019, reflecting our reduction in drilling and completion activities and the impact of voluntary production curtailments during the year. We participated in the drilling and completion of 22 gross (8 net) wells in STACK during 2020 compared to 103 gross (19 net) wells in 2019. Proved reserves in STACK decreased 46% year-over-year to 98 MMBoe as of December 31, 2020 primarily due to downward reserve revisions prompted by significantly reduced commodity prices and resulting changes in drilling plans. Our inventory of proved undeveloped drilling locations in STACK totaled 25 gross (9 net) wells as of December 31, 2020.
For 2021, our aggregate budget for exploration and development capital expenditures in the South region is $380 million. In 2021, we expect to have first production on 120 gross (57 net) operated and non-operated wells in the South region. We plan to average approximately four operated rigs and two well completion crews in the South region in 2021. Our 2021 activities will focus on continued row development in Project SpringBoard in the SCOOP play and ongoing development in areas that provide opportunities to improve capital efficiency, reduce finding and development costs, improve recoveries and rates of return, and maximize cash flows.
Production and Price History
The following table sets forth information concerning our production results, average sales prices and production costs for the years ended December 31, 2020, 2019 and 2018 in total and for each field containing 15 percent or more of our total proved reserves as of December 31, 2020.
| ||Year ended December 31,|
|Net production volumes:|
|Crude oil (MBbls)|
|North Dakota Bakken||40,052 ||52,420 ||45,775 |
|SCOOP ||12,585 ||11,679 ||6,918 |
|Total Company||58,745 ||72,267 ||61,384 |
|Natural gas (MMcf)|
|North Dakota Bakken||97,532 ||98,186 ||78,448 |
|SCOOP ||136,410 ||111,436 ||99,397 |
|Total Company||306,528 ||311,865 ||284,730 |
|Crude oil equivalents (MBoe)|
|North Dakota Bakken||56,308 ||68,784 ||58,849 |
|SCOOP ||35,320 ||30,252 ||23,484 |
|Total Company||109,833 ||124,244 ||108,839 |
|Average net sales prices (1):|
|Crude oil ($/Bbl)|
|North Dakota Bakken||$||33.53 ||$||50.96 ||$||58.37 |
|SCOOP ||37.88 ||54.92 ||62.74 |
|Total Company||34.71 ||51.82 ||59.19 |
|Natural gas ($/Mcf)|
|North Dakota Bakken||$||0.23 ||$||1.28 ||$||3.33 |
|SCOOP ||1.64 ||2.36 ||3.41 |
|Total Company||1.04 ||1.77 ||3.01 |
|Crude oil equivalents ($/Boe)|
|North Dakota Bakken||$||24.24 ||$||40.66 ||$||49.83 |
|SCOOP ||19.90 ||29.80 ||32.88 |
|Total Company||21.47 ||34.56 ||41.25 |
|Average costs per Boe:|
|Production expenses ($/Boe)|
|North Dakota Bakken||$||4.35 ||$||4.28 ||$||4.40 |
|SCOOP ||1.06 ||1.21 ||1.34 |
|Total Company||3.27 ||3.58 ||3.59 |
|Production taxes ($/Boe)||$||1.75 ||$||2.88 ||$||3.25 |
|General and administrative expenses ($/Boe)||$||1.79 ||$||1.57 ||$||1.69 |
|DD&A expense ($/Boe)||$||17.12 ||$||16.25 ||$||17.09 |
(1) See Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Non-GAAP Financial Measures for a discussion and calculation of net sales prices, which are non-GAAP measures.
The following table sets forth information regarding our average daily production by region for the fourth quarter of 2020:
| ||Fourth Quarter 2020 Daily Production|
| ||Crude Oil|
(Bbls per day)
(Mcf per day)
(Boe per day)
|North Dakota Bakken||122,291 ||333,070 ||177,802 |
|Montana Bakken||4,137 ||7,209 ||5,339 |
|Red River units|
|Cedar Hills||5,323 ||— ||5,323 |
|Other Red River units||1,464 ||17 ||1,467 |
|SCOOP||36,415 ||423,871 ||107,060 |
|STACK||6,995 ||211,715 ||42,281 |
|Other||14 ||129 ||35 |
|Total||176,639 ||976,011 ||339,307 |
Gross wells represent the number of wells in which we own a working interest and net wells represent the total of our fractional working interests owned in gross wells. The following table presents the total gross and net productive wells by region and by crude oil or natural gas completion as of December 31, 2020. One or more completions in the same well bore are counted as one well.
| ||Crude Oil Wells||Natural Gas Wells||Total Wells|
| ||Gross ||Net ||Gross ||Net ||Gross ||Net |
|North Dakota Bakken||4,708 ||1,631 ||— ||— ||4,708 ||1,631 |
|Montana Bakken||394 ||254 ||— ||— ||394 ||254 |
|Red River units|
|Cedar Hills||136 ||130 ||— ||— ||136 ||130 |
|Other Red River units||130 ||116 ||— ||— ||130 ||116 |
|SCOOP||620 ||316 ||488 ||147 ||1,108 ||463 |
|STACK||416 ||157 ||436 ||142 ||852 ||299 |
|Other||1 ||1 ||22 ||1 ||23 ||2 |
|Total||6,405 ||2,605 ||946 ||290 ||7,351 ||2,895 |
Title to Properties
As is customary in the crude oil and natural gas industry, upon initiation of acquiring oil and gas leases covering fee mineral interests on undeveloped lands which do not have associated proved reserves, contract landmen conduct a title examination of courthouse records and production databases to determine fee mineral ownership and availability. Title, lease forms and terms are reviewed and approved by Company landmen prior to consummation.
For acquisitions from third parties, whether lands are producing crude oil and natural gas or non-producing, Company and contract landmen perform title examinations at applicable courthouses, obtain physical well site inspections, and examine the seller’s internal records (land, legal, operational, production, environmental, well, marketing and accounting) upon execution of a mutually acceptable purchase and sale agreement. Company landmen may also procure an acquisition title opinion from outside legal counsel on higher value properties.
Prior to the commencement of drilling operations, Company landmen procure an original title opinion, or supplement an existing title opinion, from outside legal counsel and perform curative work to satisfy requirements pertaining to material title defects, if any. Company landmen will not approve commencement of drilling operations until material title defects pertaining to the Company’s interest are cured.
The Company has cured material title opinion defects as to Company interests on substantially all of its producing properties and believes it holds at least defensible title to its producing properties in accordance with standards generally accepted in the crude oil and natural gas industry. The Company’s crude oil and natural gas properties are subject to customary royalty and leasehold burdens which do not materially interfere with the Company’s interest in the properties or affect the Company’s carrying value of such properties.
We sell most of our operated crude oil production to crude oil refining companies or midstream marketing companies at major market centers. In the Bakken, SCOOP, and STACK areas we have significant volumes of production directly connected to pipeline gathering systems, with the remaining production primarily transported by truck to a point on a pipeline system for further delivery. We do not transport any of our oil production prior to sale by rail, but several purchasers of our Bakken production are connected to rail delivery systems and may choose those methods to transport the oil they purchase from us. We sell some operated crude oil production at the lease. Our share of crude oil production from non-operated properties is marketed at the discretion of the operators.
We sell our operated natural gas production to midstream customers at our lease locations based on market prices in the field where the sales occur. These contracts include multi-year term agreements, many with acreage dedications. Under certain arrangements, we have the right to take a volume of processed residue gas and/or natural gas liquids ("NGLs") in-kind at the tailgate of the midstream customer's processing plant in lieu of a monetary settlement for the sale of our operated natural gas production. We currently take certain processed residue gas volumes in kind in lieu of monetary settlement, but we do not currently take NGL volumes. When we do take volumes in kind, we pay third parties to transport the residue gas volumes taken in kind to downstream delivery points, where we then sell to customers at prices applicable to those downstream markets. Sales at the downstream markets are mostly under daily and monthly packaged volumes deals, shorter term seasonal packages, and long term multi-year contracts. We continue to develop relationships and have the potential to enter into additional contracts with end-use customers, including utilities, industrial users, and liquefied natural gas exporters, for sale of products we elect to take in-kind in lieu of monetary settlement for our leasehold sales. Our share of natural gas production from non-operated properties is generally marketed at the discretion of the operators.
We operate in a highly competitive environment for acquiring properties, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors vary within the regions in which we operate, and some of our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for crude oil and natural gas properties, minerals, and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions economically in a highly competitive environment. In addition, as a result of depressed commodity prices in recent years, the number of providers of materials and services has decreased in the regions where we operate. As a result, the likelihood of experiencing competition and shortages of materials and services may be further increased in connection with any period of sustained commodity price recovery. Finally, the emerging impact of climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing demand for alternative forms of energy, and
technological advances in energy generation devices may result in reduced demand for the crude oil and natural gas we produce.
Regulation of the Crude Oil and Natural Gas Industry
All of our operations are conducted onshore in the United States. The crude oil and natural gas industry in the United States is subject to various types of regulation at the federal, state and local levels. Laws, rules, regulations, policies, and interpretations affecting our industry have been and are pervasive with the frequent imposition of new or increased requirements. These laws, regulations and other requirements often carry substantial penalties for failure to comply and may have a significant effect on our operations and may increase the cost of doing business and reduce our profitability. In addition, because public policy changes affecting the crude oil and natural gas industry are commonplace and because laws, rules and regulations may be enacted, amended or reinterpreted, we are unable to predict the future cost or impact of complying with such laws, rules and regulations. We do not expect future legislative or regulatory initiatives will affect us materially different than they will affect our similarly situated competitors.
The following is a discussion of certain significant laws, rules and regulations, as amended from time to time, that may affect us in the areas in which we operate.
Regulation of sales and transportation of crude oil and natural gas liquids
Our physical sales of crude oil and any derivative instruments relating to crude oil are subject to anti-market manipulation laws and related regulations enforced by the Federal Trade Commission (“FTC”) and the Commodity Futures Trading Commission (“CFTC”). These laws, among other things, prohibit fraudulent or deceptive conduct in connection with wholesale purchases or sales of crude oil and price manipulation in the commodity and futures markets. If we violate the anti-market manipulation laws and regulations, we can be subject to substantial penalties and related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
We transport most of our operated crude oil production to market centers using a combination of trucks and pipeline transportation facilities owned and operated by third parties. The U.S. Department of Transportation’s Pipeline and Hazardous Materials Safety Administration establishes safety regulations relating to transportation of crude oil by pipeline. Further, our sales of crude oil are affected by the availability, terms and costs of transportation. The transportation of crude oil and natural gas liquids ("NGLs") is subject to rate and access regulation. The Federal Energy Regulatory Commission (“FERC”) regulates interstate crude oil and NGL pipeline transportation rates under the Interstate Commerce Act and the Energy Policy Act of 1992, and intrastate crude oil and NGL pipeline transportation rates may be subject to regulation by state regulatory commissions. As the interstate and intrastate transportation rates we pay are generally applicable to all comparable shippers, the regulation of such transportation rates will not affect us in a way that materially differs from the effect on our similarly situated competitors.
Further, interstate pipelines and intrastate common carrier pipelines must provide service on an equitable basis and offer service to all similarly situated shippers requesting service on the same terms and under the same rates. When such pipelines operate at full capacity we are subject to proration provisions, which are described in the pipelines’ published tariffs. We generally will have access to crude oil pipeline transportation services to the same extent as our similarly situated competitors.
From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. The International Maritime Organization ("IMO"), an agency of the United Nations, has issued regulations requiring the maritime shipping industry to gradually reduce its carbon emissions over time by mandating a 1% improvement in the efficiency of fleets each year between 2015 and 2025. In conjunction with this initiative, the IMO issued regulations requiring ship owners to lower the concentration of the sulfur content used in their fuels from 3.5% to 0.5% beginning on January 1, 2020. To achieve and maintain compliance with the new regulations, it is expected ship owners will either have to switch to more expensive higher quality marine fuel, install and utilize emissions-cleaning systems, or switch to alternative fuels such as liquefied natural gas. Failure to comply with the regulations may result in fines or shipping vessels being detained, thereby resulting in exportation capacity constraints that inhibit a third party's ability to transport and sell domestic crude oil production overseas, which may have a material impact on the markets and prices for various grades of domestic and international crude oil. The ultimate long-term impact of the IMO regulations is uncertain.
We do not own or operate pipeline or rail transportation facilities, rail cars, or infrastructure used to facilitate the exportation of crude oil. However, regulations that impact the domestic transportation of crude oil could increase our costs of doing business
and limit our ability to transport and sell our crude oil at market centers throughout the United States. We do not expect such regulations will affect us in a materially different way than similarly situated competitors.
Regulation of sales and transportation of natural gas
We are also required to observe the aforementioned anti-market manipulation laws and related regulations enforced by the FERC and CFTC in connection with physical sales of natural gas and any derivative instruments relating to natural gas. Additionally, the FERC regulates interstate natural gas transportation rates and service conditions under the Natural Gas Act and the Natural Gas Policy Act of 1978, which affects the marketing of natural gas we produce, as well as revenues we receive for sales of our natural gas. The FERC has endeavored to increase competition and make natural gas transportation more accessible to natural gas buyers and sellers on an open and non-discriminatory basis and has issued a series of orders to implement its open access policies. We cannot provide any assurance the pro-competitive regulatory approach established by the FERC will continue. However, we do not believe any action taken by the FERC will affect us in a materially different way than similarly situated natural gas producers.
The gathering of natural gas, which occurs upstream of jurisdictional transmission services, is generally regulated by the states. Although its policies on gathering systems have varied in the past, the FERC has reclassified certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, which has the potential to increase costs for our purchasers and reduce the revenues we receive for our natural gas stream. State regulation of natural gas gathering facilities generally includes various safety, environmental, and in some circumstances, equitable take requirements. We do not believe such regulations will affect us in a materially different way than our similarly situated competitors.
Intrastate natural gas transportation service is also subject to regulation by state regulatory agencies. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas we produce, as well as the revenues we receive for sales of our natural gas. The basis for intrastate regulation of natural gas transportation and the degree of regulatory oversight and scrutiny given to intrastate natural gas pipeline rates and services varies from state to state. Insofar as such regulation within a particular state will generally affect all intrastate natural gas shippers on a comparable basis, the regulation of intrastate natural gas transportation in states in which we operate will not affect us in a way that materially differs from our similarly situated competitors.
The U.S. Department of Energy (“U.S. DOE”) regulates the terms and conditions for the exportation and importation of natural gas (including liquefied natural gas or “LNG”). U.S. law provides for very limited regulation of exports to and imports from any country that has entered into a Free Trade Agreement (“FTA”) with the United States providing for national treatment of trade in natural gas; however, the U.S. DOE’s regulation of imports and exports from and to countries without an FTA is more comprehensive. The FERC also regulates the construction and operation of import and export facilities, including LNG terminals. Regulation of imports and exports and related facilities may materially affect natural gas markets and sales prices and could inhibit the development of LNG infrastructure.
Regulation of production
The production of crude oil and natural gas is regulated by a wide range of federal, state, and local laws, rules, and regulations, which require, among other matters, permits for drilling operations, drilling bonds, and reports concerning operations. Each of the states where we own and operate properties have laws and regulations governing conservation, including provisions for the unitization or pooling of crude oil and natural gas properties, the establishment of maximum allowable rates of production from crude oil and natural gas wells, the regulation of well spacing, the plugging and abandonment of wells, the regulation of greenhouse gas emissions, and limitations or prohibitions on the venting or flaring of natural gas. These laws and regulations directly and indirectly limit the amount of crude oil and natural gas we can produce from our wells and the number of wells and locations we can drill, although we can and do apply for exceptions to such laws and regulations or to have reductions in well spacing. Moreover, each state generally imposes a production, severance or excise tax on the production and sale of crude oil, natural gas and natural gas liquids within its jurisdiction.
The failure to comply with the above laws, rules, and regulations can result in substantial penalties. Our similarly situated competitors are generally subject to the same laws, rules, and regulations as we are.
General. We are subject to stringent and complex federal, state, and local laws, rules and regulations governing environmental compliance, including the discharge of materials into the environment. These laws, rules and regulations may, among other things:
•require the acquisition of various permits to conduct exploration, drilling and production operations;
•restrict the types, quantities and concentration of various substances that can be released into the environment in connection with crude oil and natural gas drilling, production and transportation activities;
•limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas including areas containing endangered species of plants and animals;
•require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; and
•impose substantial liabilities for pollution resulting from drilling and production operations.
These laws, rules and regulations may restrict the level of substances generated by our operations that may be emitted into the air, discharged to surface water, and disposed or otherwise released to surface and below-ground soils and groundwater, and may also restrict the rate of crude oil and natural gas production to a rate that is economically infeasible for continued production. The regulatory burden on the crude oil and natural gas industry increases the cost of doing business and affects profitability. Additionally, the U.S. Congress and federal and state legislators and agencies frequently revise environmental laws, rules and regulations and with party control of Congress shifting in January 2021, there is potential for the Biden Administration to pursue new legislation and regulatory initiatives that revise the permitting or leasing policies pursued under the Trump Administration that could adversely affect the oil and gas industry. Moreover, President Biden has issued, and may continue to issue, executive orders in pursuit of his regulatory agenda. Any changes that result in more stringent and costly waste handling, disposal, cleanup and remediation requirements for the crude oil and natural gas industry or restrict, delay or ban oil and gas permitting or leasing on federal lands could have a significant impact on our operating costs and production of oil and gas. Failure to comply with these and other laws, rules and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations or the incurrence of capital expenditures, the occurrence of restrictions, delays or cancellations in the permitting, development or expansion of projects, the issuance of orders enjoining performance of some or all of our operations, and potential litigation in a particular area. Additionally, certain of these environmental laws may result in imposition of joint and several or strict liability, which could cause us to become liable for the conduct of others or for consequences of our own actions. For instance, an accidental release from one of our wells could subject us to substantial liabilities arising from environmental cleanup and restoration costs, claims made by neighboring landowners or other third parties for personal injury and property damage and fines or penalties for related violations of environmental laws or regulations. Certain environmental laws also provide for certain citizen suits, which allow persons or organizations to act in place of the government and sue operators for alleged violations of environmental laws. We have incurred and will continue to incur operating and capital expenditures, some of which may be material, to comply with environmental laws and regulations. The following is a description of some of the environmental laws, rules and regulations that apply to our operations.
Air emissions and climate change. Federal, state, and local laws, rules, and regulations have been and, in the future, will likely be enacted to address concerns about emissions of regulated air pollutants, including the potential effects of carbon dioxide, methane and other identified “greenhouse gas” emissions on the environment and climate worldwide, generally referred to as “climate change.” For example, since 2015 the U.S. Environmental Protection Agency ("EPA") under the Obama Administration has made revisions to the National Ambient Air Quality Standard (“NAAQS”) for ground-level ozone, making the standard stricter. Since that time, the EPA under the Trump Administration has issued attainment and nonattainment designations and, on December 31, 2020, published notice of a final action, upon conducting a periodic review of the ozone standard, electing to retain the 2015 ozone NAAQS in 2020 without revision on a going-forward basis. However, this December 2020 final action is subject to legal challenge, and the NAAQS may be subject to further revision under the Biden Administration. State implementation of the revised NAAQS for ground-level ozone could result in stricter permitting requirements, a delay or prohibition on our ability to obtain such permits, or result in increased expenditures for pollution control equipment, the costs of which could be significant.
With respect to climate change and the control of greenhouse gas emissions, numerous proposals have been made and are likely to continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of greenhouse gases as well as to restrict or eliminate future emissions. Federal regulatory initiatives have focused on establishing construction and operating permit reviews for greenhouse gas emissions from certain large stationary sources, requiring the monitoring and annual reporting of greenhouse gas emissions from certain petroleum and natural gas system sources, and reducing methane emissions from oil and gas operations through limitations on venting and flaring and the implementation of enhanced emission leak detection and repair requirements. For example, in 2016 the EPA under the Obama Administration finalized new regulations (New Source Performance Standard Subpart OOOOa, commonly referred to as “Quad Oa”) setting methane emission standards for new and modified oil and gas production and natural gas processing and transmission facilities. However, in recent years following the beginning of the Trump Administration in 2017, the EPA has undertaken several measures to delay implementation of the methane standards. Recently, in September 2020, the EPA issued
its final policy and technical amendments to the 2016 final rule. The policy amendments, effective September 14, 2020, notably removed the transmission and storage sector from the regulated source category and rescinded methane and volatile organic compound requirements for the remaining sources that were established by former President Obama's Administration, whereas the technical amendments, effective November 16, 2020, included changes to fugitive emissions monitoring and repair schedules for gathering and boosting compressor stations and low-production wells, recordkeeping and reporting requirements, and more. Various states and industry and environmental groups are separately challenging both the original 2016 standards and the EPA’s September 2020 final rules and on January 20, 2021, President Biden issued an executive order that, among other things, directed the EPA to reconsider the technical amendments and issue a proposed rule suspending, revising or rescinding those amendments by no later than September 2021. A reconsideration of the September 2020 policy amendments is expected to follow. The January 20, 2021 executive order also directed the establishment of new methane and volatile organic compound standards applicable to existing oil and gas operations, including the production, transmission, processing and storage segments. Additionally, various states and groups of states have adopted or are considering adopting legislation, regulations or other regulatory initiatives that are focused on such areas as greenhouse gas cap and trade programs, carbon taxes, reporting and tracking programs, and restriction of emissions. At the international level, there exists the United Nations-sponsored "Paris Agreement," which is a non-binding agreement for nations to limit their greenhouse gas emissions through individually-determined reduction goals every five years after 2020. While the United States withdrew from the Paris Agreement under the Trump Administration, on January 20, 2021 President Biden issued an executive order recommitting the United States to the Paris Agreement and calling for the federal government to begin formulating the United States’ nationally determined emissions reduction goal under the agreement. With the United States recommitting to the Paris Agreement, executive orders may be issued or federal legislation or regulatory initiatives may be adopted to achieve the agreement’s goals, which could require us to incur increased costs to comply with such requirements.
In addition, increasing concern over the threat of climate change arising from greenhouse gas emissions has given rise to a series of political, litigation, and financial risks associated with the production and processing of hydrocarbons and emission of greenhouse gases. In addition to recommitting the United States to the Paris Agreement, on January 20, 2021, the Acting Secretary of the U.S. Department of the Interior issued an order, effective immediately, that suspends new crude oil and natural gas leases and drilling permits on non-Indian federal lands and waters for a period of 60 days. Building on this suspension, President Biden issued an executive order on January 27, 2021 that suspends new leasing activities for oil and gas exploration and production on non-Indian federal lands and offshore waters pending completion of a comprehensive study of federal oil and gas permitting and leasing practices that take into consideration potential climate and other impacts associated with oil and gas activities on such lands and waters. As of December 31, 2020, we held approximately 41,800 net undeveloped acres on federal lands.
The January 20, 2021 and January 27, 2021 executive orders do not apply to existing leases and the January 27, 2021 order further directs applicable agencies to eliminate subsidies for the oil and gas sector. Legal challenges to these orders are expected, with at least one industry group already filing a lawsuit in January 2021 in Wyoming federal district court and seeking to have the moratorium on leasing declared invalid. Litigation risks are also increasing, as a number of states, municipalities and other parties have sought to bring suit against the largest oil and natural gas exploration and production companies in state or federal court, alleging, among other things, that such companies created public nuisances by producing fuels that contributed to global warming effects, such as rising sea levels, and therefore are responsible for roadway and infrastructure damages, or that the companies have been aware of the adverse effects of climate change for some time but failed to adequately disclose those impacts. There are also increasing financial risks for oil and gas producers, as stockholders and bondholders currently invested in energy companies concerned about the potential effects of climate change may elect to shift some or all of their investments into non-energy related sectors. Institutional investors who provide financing to energy companies have also focused on sustainability issues and some of them may elect not to provide funding for energy companies. Limitation of investments in and financings for oil and gas producers could result in reduced access to capital, higher costs of capital and the restriction, delay, or cancellation of development and production activities.
While we cannot predict the outcome of legislative or regulatory initiatives related to climate change, we anticipate that initiatives to reduce greenhouse gas emissions will continue to develop. The adoption of state or federal legislation or regulatory programs to reduce greenhouse gas emissions, including methane and carbon dioxide, could require us to incur increased operating costs, such as costs to purchase and operate emissions monitoring and control systems, to acquire emissions allowances, or comply with new regulatory or reporting requirements. Additionally, political, litigation, and financial risks may result in restrictions or cancellations in development and production activities, liability for infrastructure damages due to climate changes, or increases in the cost of consuming hydrocarbons and thereby reducing demand for crude oil and natural gas. Moreover, the increased competitiveness of alternative energy sources (such as wind, solar, geothermal, tidal and biofuels) could reduce demand for hydrocarbons, including the oil and gas we produce, which could lead to a reduction in our revenues. Also, there is the possibility that financial institutions will be required to adopt policies that limit funding for energy companies as President Biden recently signed an executive order calling for the development of a climate finance plan and, separately, the
Federal Reserve announced that it has joined the Network for Greening the Financial System, a consortium of financial regulators focused on addressing climate-related risks in the financial sector. Finally, increasing concentrations of greenhouse gas in the Earth's atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, floods, rising sea levels and other climatic events. Consequently, one or more of these developments could have an adverse effect on our business, financial condition, results of operations, and cash flows.
Environmental protection and natural gas flaring. One of our environmental initiatives is the reduction of air emissions produced from our operations, including the flaring of natural gas from our operated well sites in the Bakken field of North Dakota. North Dakota law permits flaring of natural gas from a well that has not been connected to a gas gathering line for a period of one year from the date of a well’s first production. After one year, a producer is required to cap the well, connect it to a gas gathering line, find acceptable alternative uses for a percentage of the flared gas, or apply to the North Dakota Industrial Commission ("NDIC") for a written exemption for any future flaring; otherwise, the producer is required to pay royalties and production taxes based on the volume and value of the gas flared from the unconnected well.
In addition, NDIC rules for new drilling permit applications also require the submission of gas capture plans setting forth plans taken by operators to capture and not flare produced gas, regardless of whether it has been or will be connected within the first year of production. The NDIC currently requires us to capture 91% of the natural gas produced from a field. If an operator is unable to attain the applicable gas capture percentage goal at maximum efficient rate, wells will be restricted in production to 200 barrels of crude oil per day if at least 60% of the monthly volume of associated natural gas produced from the well is captured, or otherwise crude oil production from such wells is not permitted to exceed 100 barrels of crude oil per day. However, the NDIC will consider temporary exemptions from the foregoing restrictions or for other types of extenuating circumstances after notice and hearing if the effect is a significant net increase in gas capture within one year of the date such relief is granted. Monetary penalty provisions also apply under this regulation if an operator fails to timely file for a hearing with the NDIC upon being unable to meet such percentage goals or if the operator fails to timely implement production restrictions once below the applicable percentage goals. Ongoing compliance with the NDIC’s flaring requirements or the imposition of any additional limitations on flaring could result in increased costs and have an adverse effect on our operations.
We continue to strive to reduce natural gas flaring as much as practicable, but our efforts may not always be successful or cost-effective. Our levels of flaring are impacted by external factors such as investment from third parties in the development and continued operation of gas gathering and processing facilities and the granting of reasonable right-of-way access by land owners. Increased emissions from our facilities due to flaring could subject our facilities to more stringent air emission permitting requirements, resulting in increased compliance costs and potential construction delays.
Hydraulic fracturing. Hydraulic fracturing involves the injection of water, sand or other proppant and additives under pressure into rock formations to stimulate crude oil and natural gas production. In recent years there has been public concern regarding an alleged potential for hydraulic fracturing to adversely affect drinking water supplies or to induce seismic events. As a result, several federal and state agencies have studied the environmental risks with respect to hydraulic fracturing, and proposals have been made to enact separate federal, state and local legislation that would potentially increase the regulatory burden imposed on hydraulic fracturing.
At the federal level, the EPA has asserted federal regulatory authority pursuant to the federal Safe Drinking Water Act ("SDWA") over certain hydraulic fracturing activities involving the use of diesel fuels and published permitting guidance related to such activities. Also, the EPA has issued a final regulation under the Clean Water Act prohibiting discharges to publicly owned treatment works of wastewater from onshore unconventional oil and gas extraction facilities. We do not discharge wastewater to publicly owned treatment works, so the impact of this regulation on us is not currently, and is not expected to be, material.
In late 2016 the EPA published a final study of the potential impacts of hydraulic fracturing activities on water resources in which the EPA indicated it found evidence that such activities can impact drinking water resources under some circumstances. In its final report, the EPA indicated it was not able to calculate or estimate the national frequency of impacts on drinking water resources from hydraulic fracturing activities or fully characterize the severity of impacts. Nonetheless, the results of the EPA’s study or similar governmental reviews could spur initiatives to regulate hydraulic fracturing under the SDWA or otherwise.
In 2016, the BLM under the Obama Administration published final rules related to the regulation of hydraulic fracturing activities on federal lands, including requirements for chemical disclosure, well bore integrity, and handling of flowback water. However, the BLM under the Trump Administration published a final rule rescinding the 2016 final rule in November 2018. Litigation challenging the BLM's 2016 final rule as well as its 2018 final rule rescinding the 2016 rule has been pursued by various states and industry and environmental groups. While a California federal court vacated the 2018 final rule in July 2020, a Wyoming federal court subsequently vacated the 2016 final rule in October 2020 and, accordingly, the 2016 final rule is no
longer in effect. The Wyoming decision is expected to be appealed. Moreover, the BLM under a Biden Administration could seek to pursue regulatory initiatives that regulate hydraulic fracturing activities on federal lands.
While the U.S. Congress has from time to time considered but refused to adopt federal regulation of hydraulic fracturing, there is a possibility that a Biden Administration will pursue such legislation. In addition to pursuing the revision of existing laws and regulations, President Biden has issued, and may continue to issue, additional executive orders in pursuit of his regulatory agenda with regards to limiting hydraulic fracturing.
In addition, regulators in states in which we operate have adopted additional requirements related to seismicity and its potential association with hydraulic fracturing. For example, the Oklahoma Corporation Commission (the “OCC”) has promulgated guidance for operators of crude oil and natural gas wells in certain seismically-active areas of the SCOOP and STACK plays in Oklahoma. The OCC's guidance provides for seismic monitoring and for implementation of mitigation procedures, which may include curtailment or even suspension of operations in the event of concurrent seismic events within a particular radius of operations of a magnitude exceeding 2.5 on the Richter scale. If seismic events exceeding the OCC guidance thresholds were to occur near our active stimulation operations on a frequent basis, they could have an adverse effect on our operations.
Waste water disposal. Underground injection wells are a predominant method for disposing of waste water from oil and gas activities. In response to seismic events near underground injection wells used for the disposal of oil and gas-related waste waters, federal and some state agencies have investigated whether such wells have caused increased seismic activity. To address concerns regarding seismicity, some states, including states in which we operate, have pursued remedies that included delaying permit approvals, mandating a reduction in injection volumes, or shutting down or imposing moratoria on the use of injection wells. Moreover, regulators in states in which we operate have implemented additional requirements related to seismicity. For example, the OCC has adopted rules for operators of saltwater disposal wells in certain seismically-active areas in the Arbuckle formation of Oklahoma. These rules require, among other things, that disposal well operators conduct mechanical integrity testing or make certain demonstrations of such wells’ respective depths that, depending on the depth, could require plugging the well and/or the reduction of volumes disposed in such wells. Oklahoma utilizes a “traffic light” system wherein the OCC reviews new or existing disposal wells for proximity to faults, seismicity in the area and other factors in determining whether such wells should be permitted, permitted only with special restrictions, or not permitted. At the federal level, the EPA’s current regulatory requirements for such wells do not require the consideration of seismic impacts when issuing permits. We cannot predict the EPA’s future actions in this regard.
The introduction of new environmental laws and regulations related to the disposal of wastes associated with the exploration, development or production of hydrocarbons could limit or prohibit our ability to utilize underground injection wells. A lack of waste water disposal sites could cause us to delay, curtail or discontinue our exploration and development plans. Additionally, increased costs associated with the transportation and disposal of produced water, including the cost of complying with regulations concerning produced water disposal, may reduce our profitability. These costs are commonly incurred by oil and gas producers and we do not expect the costs associated with the disposal of produced water will have a material adverse effect on our operations to any greater degree than other similarly situated competitors. In recent years, we have increased our operation and use of water recycling and distribution facilities in Oklahoma that economically reuse stimulation water for both operational efficiencies and environmental benefits.
We have incurred in the past, and expect to incur in the future, capital and other expenditures related to environmental compliance. Such expenditures are included within our overall capital and operating budgets and are not separately itemized. Historically, our environmental compliance costs have not had a material adverse impact on our financial condition and results of operations; however, there can be no assurance that such costs will not be material in the future or that such future compliance will not have a material impact on our business, financial condition, results of operations or cash flows.
Employee Health and Safety. We are also subject to the requirements of the federal Occupational Safety and Health Act and comparable state laws that regulate the protection of the health and safety of workers. In addition, the U.S. Occupational Safety and Health Administration hazard communication standard, the EPA community right-to-know regulation under Title III of the federal superfund Amendment and Reauthorization Act and similar state laws and regulations require information be maintained about hazardous materials used or produced in operations and this information be provided to employees, state and local governmental authorities and citizens.
Employees and Labor Relations
As of December 31, 2020, we employed 1,201 people, all of which were employed in the United States, with 716 employees being located at our corporate headquarters in Oklahoma City, Oklahoma and 485 employees located in our field offices located in Oklahoma, North Dakota, South Dakota, and Montana. None of our employees are subject to collective bargaining agreements. We believe our overall relations with our workforce are good.
Because we operate in a highly competitive environment, we have designed our compensation program to attract, retain and motivate experienced, talented individuals. Our program is also designed to align employee’s interests with those of our shareholders and to reward them for achieving the business and strategic objectives determined to be important to help the Company create and maintain advantage in a competitive environment. We align our employee’s interests with those of our shareholders by making annual restricted stock awards to virtually all of our employees. We reward our employees for their performance in helping the Company achieve its annual business and strategic objectives through our bonus program, which is also available to virtually all of our employees. In order to ensure our compensation package remains competitive and fulfills our goal of recruiting and retaining talented employees, we consider competitive market compensation paid by other companies comparable to the Company in size, geographic location, and operations.
Safety is our highest priority and one of our core values. We promote safety with a robust health and safety program that includes employee orientation and training, contractor management, risk assessments, hazard identification and mitigation, audits, incident reporting and investigation, and corrective/preventative action development.
Through our “Brother’s Keeper” program, we encourage each of our employees to be a proactive participant in ensuring the safety of all of the Company’s personnel. We developed this program to leverage and continuously improve our ability to identify and prevent reoccurrence of unsafe behaviors and conditions. This program recognizes and rewards any employee or contractor working on one of our locations who observes and reports outstanding safety and environmental behavior such as utilizing stop work authority, looking out for a co-worker, reporting incidents and near misses, or following proper safety procedures. This program positively impacts safety performance and has contributed to a substantial increase in our reporting rates and to decreases in recordable incident and lost time incident rates. Our Total Recordable Incident Rate (TRIR), a commonly used safety metric that measures the number of recordable incidents per 100 full-time employees and contractors during a one year period, has decreased sequentially in each of the past three years and measured 0.40 for 2020, a 53% decrease compared to 2017.
Training and Development
We are committed to the training and development of our employees. We believe that supporting our employees in achieving their career and development goals is a key element of our approach to attracting and retaining top talent. We have invested in a variety of resources to support employees in achieving their career and development goals, including developing learning paths for individual contributors and leaders, creating the Continental Leadership Learning Center which offers numerous different instructor-led programs which foster employee development and acquiring a learning management system which provides access to numerous technical and soft skills online courses. We also invest time and resources in supporting the creation of individual development plans for our employees.
Health and Wellness
We offer various benefit programs designed to promote the health and well-being of our employees and their families. These benefits include medical, dental, and vision insurance plans; disability and life insurance plans; paid time off for holidays, vacation, sick leave, and other personal leave; and healthcare flexible spending accounts, among other things. In addition to these programs, we have a number of other programs designed to further promote the health and wellness of our employees. For instance, employees at our corporate headquarters have access to our fitness center. Additionally, we have an employee assistance program that offers counseling and referral services for a broad range of personal and family situations. We also offer a wellness plan that includes annual biometric screenings, flu shots, smoking cessation programs, and healthy snack options in our break rooms to encourage total body wellness.
In response to the COVID-19 pandemic, commencing in the first quarter of 2020, we have taken, and continue to take, proactive measures to protect the health and safety of our employees. These measures have included the implementation of a voluntary testing program to provide our employees and their household members with reliable and timely test results when
public testing options were limited and restricted, maintaining social distancing policies, limiting the number of employees attending meetings, reducing the number of people at our sites, requiring the use of masks in certain circumstances, suspending employee business travel, requiring employees to complete daily self-screening questionnaires, performing temperature checks, frequently and extensively disinfecting common areas, performing rigorous contact tracing protocols, and implementing self-isolation and quarantine requirements, among other things. We are committed to maintaining best practices with our COVID-19 response protocols and will continue to work under the guidance of public health officials to ensure a safe workplace as long as COVID-19 remains a threat to our employees and communities.
Diversity and Inclusion
We are committed to providing a diverse and inclusive workplace and career development opportunities to attract and retain talented employees. We recognize that a diverse workforce provides the best opportunity to obtain unique perspectives, experiences, ideas, and solutions to help our business succeed. To that end, we prohibit discrimination and harassment of any type and afford equal employment opportunities to employees and applicants without regard to race, color, religion, sex, national origin, age, disability, genetic information, veteran status, or any other basis protected by local, state, or federal law. Further, we forbid retaliation against any individual who reports, claims, or makes a charge of discrimination or harassment, fraud, unethical conduct, or a violation of our Company policies. To sustain and promote an inclusive culture, we maintain a robust compliance program rooted in our Code of Business Conduct and Ethics, which provides policies and guidance on non-discrimination, anti-harassment, and equal employment opportunities. We require all employees to complete periodic training sessions on various aspects of our Code of Business Conduct and Ethics and other corporate policies through an annual acknowledgement and certification process. We evaluate ways to enhance awareness of diversity and inclusion on an ongoing basis in an effort to continue improving our approach.
Company Contact Information
Our corporate internet website is www.clr.com. Through the investor relations section of our website, we make available free of charge our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and any amendments to those reports as soon as reasonably practicable after the report is filed with or furnished to the SEC. For a current version of various corporate governance documents, including our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and the charters for various committees of our Board of Directors, please see our website. We intend to disclose amendments to, or waivers from, our Code of Business Conduct and Ethics by posting to our website. Information contained on our website is not incorporated by reference into this report and you should not consider information contained on our website as part of this report.
We intend to use our website as a means of disclosing material information and for complying with our disclosure obligations under SEC Regulation FD. Such disclosures will be included on our website in the “Investors” section. Accordingly, investors should monitor that portion of our website in addition to following our press releases, SEC filings and public conference calls and webcasts.
We electronically file periodic reports and proxy statements with the SEC. The SEC maintains an internet website that contains reports, proxy and information statements, and other information registrants file with the SEC. The address of the SEC’s website is www.sec.gov.
Our principal executive offices are located at 20 N. Broadway, Oklahoma City, Oklahoma 73102, and our telephone number at that address is (405) 234-9000.
Item 1A. Risk Factors
You should carefully consider each of the risks described below, together with all other information contained in this report in connection with an investment in our securities. If any of the following risks develop into actual events, our business, financial condition, results of operations, or cash flows could be materially adversely affected, the trading price of our securities could decline and you may lose all or part of your investment.
Business and Operating Risks
Substantial declines in commodity prices or extended periods of low commodity prices adversely affect our business, financial condition, results of operations and cash flows and our ability to meet our capital expenditure needs and financial commitments.
The prices we receive for sales of our crude oil and natural gas production impact our revenue, profitability, cash flows, access to capital, capital budget, rate of growth, and carrying value of our properties. Crude oil and natural gas are commodities and prices are subject to wide fluctuations in response to relatively minor changes in supply and demand. Historically, the markets for crude oil and natural gas have been volatile and unpredictable. For example, during 2020 the NYMEX West Texas Intermediate (“WTI”) crude oil and Henry Hub natural gas spot prices ranged from negative $36.98 to positive $63.27 per barrel and $1.33 to $3.14 per MMBtu, respectively. Commodity prices will likely remain volatile and unpredictable in 2021 and beyond. A significant portion of our future crude oil and natural gas production is unhedged as of the time of this filing and is exposed to continued volatility in market prices, whether favorable or unfavorable.
The prices we receive for sales of our production depend on numerous factors beyond our control. These factors include, but are not limited to, the following:
•worldwide, domestic, and regional economic conditions impacting the supply of, and demand for, crude oil, natural gas, and natural gas liquids;
•the actions of the Organization of Petroleum Exporting Countries and other petroleum producing nations;
•the nature, extent, and impact of domestic and foreign governmental laws, regulations, and taxation, including environmental laws and regulations governing the imposition of trade restrictions and tariffs;
•executive, regulatory or legislative actions by Congress, the Biden Administration, or states in which we operate;
•geopolitical events and conditions, including domestic political uncertainty or foreign regime changes that impact government energy policies;
•the level of global, national, and regional crude oil and natural gas exploration and production activities;
•the level of global, national, and regional crude oil and natural gas inventories, which may be impacted by economic sanctions applied to certain producing nations;
•the level and effect of speculative trading in commodity futures markets;
•the relative strength of the United States dollar compared to foreign currencies;
•the price and quantity of imports of foreign crude oil;
•the price and quantity of exports of crude oil or liquefied natural gas from the United States;
•military and political conditions in, or affecting other, crude oil-producing and natural gas-producing nations;
•localized supply and demand fundamentals;
•the cost and availability, proximity and capacity of transportation, processing, storage and refining facilities for various quantities and grades of crude oil, natural gas, and natural gas liquids;
•adverse weather conditions, natural disasters, and national and global health epidemics and concerns, including the COVID-19 pandemic;
•technological advances affecting energy production and consumption;
•the effect of worldwide energy conservation and greenhouse emission limitations or other environmental protection efforts; and
•the price and availability of alternative fuels or other energy sources.
Sustained material declines in commodity prices reduce cash flows available for capital expenditures, repayment of indebtedness and other corporate purposes; may limit our ability to borrow money or raise additional capital; and may reduce our proved reserves and the amount of crude oil and natural gas we can economically produce.
In addition to reducing our revenue, cash flows and earnings, depressed prices for crude oil and/or natural gas may adversely affect us in a variety of other ways. If commodity prices decrease substantially, some of our exploration and development projects could become uneconomic, and we may also have to make significant downward adjustments to our estimated proved reserves and our estimates of the present value of those reserves. If these price effects occur, or if our estimates of production or economic factors change, accounting rules may require us to write down the carrying value of our crude oil and/or natural gas properties.
Lower commodity prices may also lead to reductions in our drilling and completion programs, which may result in insufficient production to satisfy our transportation and processing commitments. If production is not sufficient to meet our commitments we would incur deficiency fees that would need to be paid absent any cash inflows generated from the sale of production.
Lower commodity prices may also reduce our access to capital and lead to a downgrade or other negative rating action with respect to our credit rating. A downgrade of our credit rating could negatively impact our cost of capital, increase borrowing costs under our revolving credit facility, and limit our ability to access capital markets and execute aspects of our business plans. As a result, substantial declines in commodity prices or extended periods of low commodity prices may materially and adversely affect our future business, financial condition, results of operations, cash flows, liquidity and ability to meet our capital expenditure needs and commitments.
The ability or willingness of Saudi Arabia and other members of OPEC, and other oil exporting nations, including Russia, to set and maintain production levels has a significant impact on crude oil prices.
The Organization of Petroleum Exporting Countries ("OPEC") is an intergovernmental organization that seeks to manage the price and supply of crude oil on the global energy market. Actions taken by OPEC members, including those taken alongside other oil exporting nations such as Russia, may have a significant impact on global oil supply and pricing. For example, OPEC and certain other oil exporting nations have previously agreed to take measures, including production cuts, to support crude oil prices. However, in March 2020, members of OPEC and Russia were unable to agree on production levels and, in response, Saudi Arabia announced it would significantly increase production and cut the prices at which it sold crude oil. These actions, coupled with the economic impact and uncertainty from the COVID-19 pandemic, led to a sudden and drastic decrease in crude oil prices in March 2020, which materially impacted our business, results of operations, and cash flows. It is not certain what impact current or future agreements or disagreements among these parties will have on crude oil prices, particularly in light of the significant decrease in crude oil demand resulting from the COVID-19 pandemic. There can be no assurance that OPEC members and other oil exporting nations will comply with agreed-upon production cuts, agree to further production cuts in the future, or utilize other actions to support and stabilize oil prices, nor can there be any assurance they will not increase production or deploy other actions aimed at reducing oil prices. Uncertainty regarding future actions to be taken by OPEC members or other oil exporting countries could lead to increased volatility in the price of oil, which could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
Our business operations, financial position, results of operations, and cash flows have been and may continue to be materially and adversely affected by the COVID-19 pandemic.
The COVID-19 pandemic has negatively impacted, and will likely continue to negatively impact, the global economy which has led to, among other things, reduced global demand for crude oil, disruption of global supply chains, and significant volatility and disruption of financial and commodity markets.
We began to experience material decreases in our revenues in the first quarter of 2020, which negatively impacted our business, financial condition, results of operations, cash flows and outlook during 2020. The adverse effects of COVID-19 included or may in the future include the following:
•Historically low crude oil prices;
•Limitations on storage and transportation capacity and an inability to market our production;
•Curtailment or shutting in of production;
•Delay or cessation of drilling and completion projects;
•Insufficient production to satisfy transportation and processing commitments;
•Impairment of assets;
•Downgrades or other negative credit rating actions resulting in increased borrowing costs;
•An inability to develop acreage before lease expiration;
•A reduction in the volume and value of proved reserves from price declines, changes in drilling programs, and the effects of shutting in production;
•Our ability to repay or refinance indebtedness, increase our credit facility commitments, borrow money, or raise capital;
•Disruptions in energy industry supply chains;
•Credit losses due to insolvency of customers, joint interest owners, and counterparties;
•Cyber incidents or information security breaches resulting in information theft, data corruption, operational disruption, and/or financial loss as a consequence of employees accessing information from remote work locations; and
•Shortages of drilling rigs, well completion crews, field services, personnel, and equipment in future periods of commodity price recovery.
The extent to which COVID-19 and depressed crude oil prices impacts our results of operations, financial position and liquidity will depend on future developments, which are uncertain and cannot be predicted, including but not limited to, the availability of effective treatments and vaccines, the ultimate duration of the pandemic, and how quickly and to what extent normal economic and operating conditions can resume. Therefore, the degree and duration of the adverse financial impact of the pandemic cannot be reasonably estimated at this time.
Our producing properties are located in limited geographic areas, making us vulnerable to risks associated with having geographically concentrated operations.
A significant portion of our producing properties is located in the Bakken field of North Dakota and Montana, with that area comprising 53% of our crude oil and natural gas production and 61% of our crude oil and natural gas revenues for the year ended December 31, 2020. Approximately 46% of our estimated proved reserves were located in the Bakken as of December 31, 2020. Additionally, our properties in Oklahoma comprised 45% of our crude oil and natural gas production and 35% of our crude oil and natural gas revenues for the year ended December 31, 2020. Approximately 52% of our estimated proved reserves were located in Oklahoma as of December 31, 2020.
Because of this concentration in limited geographic areas, the success and profitability of our operations may be disproportionately exposed to regional factors compared to competitors having more geographically dispersed operations. These factors include, among others: (i) our reliance on a limited number of pipelines to deliver our production to markets, (ii) the prices of crude oil and natural gas produced from wells in the regions and other regional supply and demand factors, including gathering, pipeline and rail transportation capacity constraints; (iii) the availability of rigs, completion crews, waste water disposal wells, equipment, field services, water, supplies, and labor; (iv) the availability of processing and refining facilities; and (v) infrastructure capacity. In addition, our operations in the Bakken field and Oklahoma may be adversely affected by severe weather events such as floods, blizzards, extreme cold, ice storms, drought, and tornadoes, which can intensify competition for the items and services described above and may result in periodic shortages. The concentration of our operations in limited geographic areas also increases our exposure to changes in local laws and regulations, certain lease stipulations designed to protect wildlife, and unexpected events that may occur in the regions such as natural disasters, seismic events (which may result in third-party lawsuits), industrial accidents, labor difficulties, civil disturbances, public protests, cyber attacks, or terrorist attacks. Any one of these events has the potential to cause producing wells to be shut-in, delay operations, decrease cash flows, increase operating and capital costs and prevent development of lease inventory before expiration. Any of the risks described above could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Drilling for and producing crude oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. We may not be insured for, or our insurance may be inadequate to protect us against, these risks.
Our future financial condition and results of operations depend on the success of our exploration, development and production activities. Our crude oil and natural gas exploration and production activities are subject to numerous risks, including the risk that drilling will not result in commercially viable crude oil or natural gas production. Our decisions to purchase, explore, or develop prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data, and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing and operating wells may be uncertain before drilling commences.
In this report, we describe some of our current prospects and plans to develop our key operating areas. Our management has specifically identified prospects and scheduled drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. Our ability to drill and develop these locations is subject to a number of risks and uncertainties as described herein. If future drilling results do not establish sufficient reserves to achieve an economic return, we may curtail our drilling and completion activities. Prospects we decide to drill that do not produce crude oil or natural gas in expected quantities may adversely affect our results of operations, financial condition, and rates of return on capital employed. The use of seismic data and other technologies and the study of producing fields in the same area will not enable us to know conclusively prior to drilling whether crude oil or natural gas will be present in expected or economically producible quantities. We cannot assure you the wells we drill will be as productive as anticipated or whether the analogies we draw from other wells, more fully explored prospects, or producing fields will be applicable to our drilling prospects. Because of these uncertainties, we do not know if our potential drilling locations will ever be drilled or if we will be able to produce crude oil or natural gas from these or any other potential drilling locations in sufficient quantities to achieve an economic return.
Risks we face while drilling include, but are not limited to, failing to place our well bore in the desired target producing zone; not staying in the desired drilling zone while drilling horizontally through the formation; failing to run our casing the entire length of the well bore; and not being able to run tools and other equipment consistently through the horizontal well bore. Risks we face while completing our wells include, but are not limited to, not being able to fracture stimulate the planned number of stages; failing to run tools the entire length of the well bore during completion operations; not successfully cleaning out the well bore after completion of the final fracture stimulation stage; increased seismicity in areas near our completion activities; unintended interference of completion activities performed by us or by third parties with nearby operated or non-operated wells being drilled, completed, or producing; and failure of our optimized completion techniques to yield expected levels of production.
Further, many factors may occur that cause us to curtail, delay or cancel scheduled drilling and completion projects, including but not limited to:
•abnormal pressure or irregularities in geological formations;
•shortages of or delays in obtaining equipment or qualified personnel;
•shortages of or delays in obtaining components used in fracture stimulation processes such as water and proppants;
•delays associated with suspending our operations to accommodate nearby drilling or completion operations being conducted by other operators;
•mechanical difficulties, fires, explosions, equipment failures or accidents, including ruptures of pipelines or storage facilities, or train derailments;
•restrictions on the use of underground injection wells for disposing of waste water from oil and gas activities;
•political events, public protests, civil disturbances, terrorist acts or cyber attacks;
•decreases in, or extended periods of low, crude oil and natural gas prices;
•environmental hazards, such as uncontrollable flows of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants into the environment, including groundwater and shoreline contamination;
•adverse weather conditions and natural disasters;
•spillage or mishandling of crude oil, natural gas, brine, well fluids, hydraulic fracturing fluids, toxic gas or other pollutants by us or by third party service providers;
•limitations in infrastructure, including transportation, processing, refining and exportation capacity, or markets for crude oil and natural gas; and
•delays imposed by or resulting from compliance with regulatory requirements including permitting.
Any of the above 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 or destruction of property, natural resources and equipment;
•pollution and other environmental damage;
•regulatory investigations and penalties;
•suspension of our operations;
•repair and remediation costs; and
We are not insured against all risks associated with our business. We may elect to not obtain insurance if we believe the cost of available insurance is excessive relative to the risks presented or for other reasons. In addition, pollution and environmental risks are generally not fully insurable.
Losses and liabilities arising from any of the above events could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations and cash flows.
Reserve estimates depend on many assumptions that may turn out to be inaccurate. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated crude oil and natural gas reserves. Any material inaccuracies in our reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. The Company’s current estimates of reserves could change, potentially in material amounts, in the future due to changes in commodity prices, business strategies, and other factors. Additionally, unless we replace our crude oil and natural gas reserves, our total reserves and production will decline, which could adversely affect our cash flows and results of operations.
The process of estimating crude oil and natural gas reserves is complex and inherently imprecise. It requires interpretation of available technical data and many assumptions, including assumptions relating to current and future economic conditions, production rates, drilling and operating expenses, and commodity prices. Any significant inaccuracy in these interpretations or assumptions could materially affect our estimated quantities and present value of our reserves. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves for information about our estimated crude oil and natural gas reserves, standardized measure of discounted future net cash flows, and PV-10 as of December 31, 2020.
In order to prepare reserve estimates, we must project production rates and the amount and timing of development expenditures. We must also analyze available geological, geophysical, production and engineering data in preparing reserve estimates. The extent, quality and reliability of this data can vary which in turn can affect our ability to model the porosity, permeability and pressure relationships in unconventional resources. The process also requires economic assumptions, based on historical data projected into the future, about crude oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes, and availability of funds.
Actual future production, crude oil and natural gas sales prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable crude oil and natural gas reserves will vary and could vary significantly from our estimates. Any significant variance could materially affect the estimated quantities and present value of our reserves, which in turn could have an adverse effect on the value of our assets. In addition, we may remove or adjust estimates of proved reserves, potentially in material amounts, to reflect production history, results of exploration and development activities, changes in business strategies, prevailing crude oil and natural gas prices and other factors, some of which are beyond our control.
You should not assume the present value of future net revenues from our proved reserves is the current market value of our estimated crude oil and natural gas reserves. We base the estimated discounted future net revenues from proved reserves on the 12-month unweighted arithmetic average of the first-day-of-the-month commodity prices for the preceding twelve months. Actual future prices may be materially higher or lower than the average prices used in the calculations. In addition, the use of a 10% discount factor, which is required by the SEC to be used to calculate discounted future net revenues for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our reserves or the crude oil and natural gas industry. For the year ended December 31, 2020, average prices used to calculate our estimated proved reserves were $39.57 per Bbl for crude oil and $1.99 per MMBtu for natural gas ($34.34 per Bbl for crude oil and $1.17 per Mcf for natural gas adjusted for location and quality differentials). NYMEX WTI crude oil and Henry Hub natural gas first-day-of-the-month commodity prices for January 1, 2021 and February 1, 2021 averaged $51.04 per barrel and $2.53 per MMBtu, respectively. See Part I, Item 1. Business—Crude Oil and Natural Gas Operations—Proved Reserves—Proved Reserve, Standardized Measure, and PV-10 Sensitivities for proved reserve sensitivities under certain increasing and decreasing commodity price scenarios.
In addition, the development of our proved undeveloped reserves may take longer than anticipated and may not be ultimately developed or produced. At December 31, 2020, approximately 43% of our total estimated proved reserves (by volume) were
undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling operations. Our reserve estimates assume we can and will make these expenditures and conduct these operations successfully. These assumptions may not prove to be accurate. Our reserve report at December 31, 2020 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $3.9 billion. We cannot be certain the estimated costs of the development of these reserves are accurate, development will occur as scheduled, or the results of such development will be as estimated. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves as a result of our inability to fund necessary capital expenditures or otherwise, we will be required to remove the associated volumes from our reported proved reserves. Proved undeveloped reserves generally must be drilled within five years from the date of initial booking under SEC reserve rules. Changes in the timing of development plans that impact our ability to develop such reserves in the required time frame have resulted, and will likely in the future result, in fluctuations in reserves between periods as reserves booked in one period may need to be removed in a subsequent period. In 2020, 107 MMBoe of proved undeveloped reserves were removed from our year-end reserve estimates associated with locations no longer scheduled to be drilled within five years from the date of initial booking primarily due to a reduction in the scope of our future drilling programs based on adverse market conditions, reduced demand, and lower prices caused by the COVID-19 pandemic.
Additionally, unless production is established within the spacing units covering the undeveloped acres on which some of the locations are identified, the leases for such acreage will expire. If we are not able to renew leases before they expire, any proved undeveloped reserves associated with such leases will be removed from our proved reserves. The combined net acreage expiring in the next three years represents 50% of our total net undeveloped acreage at December 31, 2020. At that date, we had leases representing 61,293 net acres expiring in 2021, 69,609 net acres expiring in 2022, and 49,475 net acres expiring in 2023.
Furthermore, unless we conduct successful exploration, development and exploitation activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing crude oil and natural gas reservoirs are generally characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future crude oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing our current reserves and economically finding or acquiring additional recoverable reserves. We may not be able to develop, find or acquire sufficient additional reserves to replace our current and future production. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations could be materially adversely affected.
Our business depends on crude oil and natural gas transportation, processing, refining, and export facilities, most of which are owned by third parties.
The value we receive for our crude oil and natural gas production depends in part on the availability, proximity and capacity of gathering, pipeline and rail systems and processing, refining, and export facilities owned by third parties. The inadequacy or unavailability of capacity on these systems and facilities could result in the shut-in of producing wells, the delay or discontinuance of development plans for properties, or higher operational costs associated with air quality compliance controls. Although we have some contractual control over the transportation of our products, changes in these business relationships or failure to obtain such services on acceptable terms could adversely affect our operations. If our production becomes shut-in for any of these or other reasons, we will be unable to realize revenue from those wells until other arrangements are made for the sale or delivery of our products and acreage lease terminations could result if production is shut-in for a prolonged period.
The disruption of transportation, processing, refining, or export facilities due to contractual disputes or litigation, labor disputes, maintenance, civil disturbances, international trade disputes, public protests, terrorist attacks, cyber attacks, adverse weather, natural disasters, seismic events, health epidemics and concerns, changes in tax and energy policies, federal, state and international regulatory developments, changes in supply and demand, equipment failures or accidents, including pipeline and gathering system ruptures or train derailments, and general economic conditions could negatively impact our ability to achieve the most favorable prices for our crude oil and natural gas production. We have no control over when or if access to such facilities would be restored or the impact on prices in the areas we operate. A significant shut-in of production in connection with any of the aforementioned items could materially affect our cash flows, and if a substantial portion of the impacted production fulfills transportation or processing commitments or is hedged at lower than market prices, those commitments or financial hedges would have to be paid from borrowings in the absence of sufficient operating cash flows.
Our operated crude oil and natural gas production is ultimately transported to downstream market centers in the United States primarily using transportation facilities and equipment owned and operated by third parties. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of regulations impacting the transportation of crude oil and natural gas. From time to time we may sell our operated crude oil production at market centers in the United States to third parties who then subsequently export and sell the crude oil in international markets. We do not currently own or operate infrastructure used to facilitate the transportation and exportation of crude oil; however, third party compliance with regulations
that impact the transportation or exportation of our production may increase our costs of doing business and inhibit a third party's ability to transport and sell our production, whether domestically or internationally, the consequences of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
On July 6, 2020, the U.S. District Court for the District of Columbia ruled that the U.S. Army Corps of Engineers (“Corps”), which had previously issued an easement near tribal lands allowing the Dakota Access Pipeline (“DAPL”) to cross a water body, had failed to adequately consider the environmental impacts under the National Environmental Protection Act (“NEPA”) arising out of such pipeline crossing this water body, and directed the Corps to prepare a new environmental impact statement (“EIS”) as well as ordering the owners of DAPL to shut down the pipeline pending completion of the EIS. The DAPL is owned and operated by a third party and carries Bakken-produced crude oil from North Dakota to Illinois. The pipeline owner sought an emergency stay of the shut-down order from the U.S. Court of Appeals for the District of Columbia Circuit (the “Appeals Court”). On July 14, 2020, the Appeals Court issued a temporary administrative stay of such order, which has allowed the pipeline to continue operating. On January 26, 2021, the Appeals Court affirmed that part of the lower court decision vacating the Corps’ easement while it prepares a new EIS, but reversed the lower court’s order to shut down the pipeline because the lower court had not properly evaluated such a move under an applicable NEPA factoring test established under case law. As stated by the Appeals Court, the Corps is within its authority to shut down the pipeline and the Appeals Court would expect the Corps to make that decision “promptly.” On February 9, 2021, the Corps, through the Department of Justice, sought a delay of the proceedings to give lawyers time to brief the new presidential administration on the background of the DAPL matter. Accordingly, the continued operation of DAPL in the future is uncertain. The Company utilizes DAPL to transport a portion of its North region crude oil production to ultimate markets on the U.S. gulf coast. Currently, the Company is committed to transport 3,550 barrels per day on the pipeline through February 2026 and has an additional commitment to transport an incremental 26,450 barrels per day for 7 years effective upon the pending completion of a DAPL expansion project which is estimated to occur in the second half of 2021. If transportation capacity on DAPL becomes restricted or unavailable, we have the ability to utilize other third party pipelines or rail facilities to transport our Bakken crude oil production to market, although such alternatives may be more costly. A restriction of DAPL’s takeaway capacity may have an impact on prices for Bakken-produced barrels and result in wider differentials relative to WTI benchmark prices in the future, the amount of which is uncertain.
Our exploration, development and exploitation projects require substantial capital expenditures. We may be unable to obtain needed capital or financing on acceptable terms, which could lead to a decline in our crude oil and natural gas reserves, production and revenues.
The crude oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures in our business for the exploration, development, exploitation, production and acquisition of crude oil and natural gas reserves. We have budgeted $1.40 billion for capital expenditures attributable to us in 2021 of which approximately $1.11 billion is allocated to exploration and development activities. We may adjust our 2021 capital spending plans upward or downward depending on market conditions. Our 2021 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded from operating cash flows. However, the sufficiency of our cash flows from operations is subject to a number of variables, including but not limited to:
•the prices at which crude oil and natural gas are sold;
•the volume of our proved reserves;
•the volume of crude oil and natural gas we are able to produce and sell from existing wells; and
•our ability to acquire, locate and produce new reserves;
If oil and gas industry conditions weaken as a result of low commodity prices or other factors, we may not be able to generate sufficient cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or planned levels. A decline in cash flows from operations may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities.
We have a revolving credit facility with lender commitments totaling $1.5 billion that matures in April 2023. In the future, we may not be able to access adequate funding under our revolving credit facility if our lenders are unwilling or unable to meet their funding obligations or increase their commitments under the credit facility. Our lenders could decline to increase their commitments based on our financial condition, the financial condition of our industry or the economy as a whole or for other reasons beyond our control. Due to these and other factors, we cannot be certain that funding, if needed, will be available to the extent required or on terms we find acceptable. If operating cash flows are insufficient and we are unable to access funding or execute capital transactions when needed on acceptable terms, we may not be able to fully implement our business plans, fund our capital program and commitments, complete new property acquisitions to replace reserves, take advantage of business
opportunities, respond to competitive pressures, or refinance debt obligations as they come due. Should any of the above risks occur, they could have a material adverse effect on our business, financial condition, results of operations and cash flows.
The unavailability or high cost of drilling rigs, well completion crews, water, equipment, supplies, personnel and field services could adversely affect our ability to execute our exploration and development plans within budget and on a timely basis.
In the regions in which we operate, there have been shortages of drilling rigs, well completion crews, equipment, personnel, field services, and supplies, including key components used in fracture stimulation processes such as water and proppants, as well as high costs associated with these critical components of our operations. With current technology, water is an essential component of drilling and hydraulic fracturing processes. The availability of water sources and disposal facilities is becoming increasingly competitive, constrained, subject to social and regulatory scrutiny, and impacted by third-party supply chains over which we may have limited control. Limitations or restrictions on our ability to secure, transport, and use sufficient amounts of water, including limitations resulting from natural causes such as drought, could adversely impact our operations. In some cases, water may need to be obtained from new sources and transported to drilling or completion sites, resulting in increased costs.
The demand for qualified and experienced field service providers and associated equipment, supplies, and materials can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages and/or higher costs. Such shortages or higher costs could delay the execution of our drilling and development plans or cause us to incur expenditures not provided for in our capital budget or to not achieve the rates of return we are targeting for our development program, all of which could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We have been an early entrant into new or emerging plays. As a result, our drilling results in these areas are uncertain, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
While our costs to acquire undeveloped acreage in new or emerging plays have generally been less than those of later entrants into a developing play, our drilling results in new or emerging areas are more uncertain than drilling results in developed and producing areas. Since new or emerging plays have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage in the emerging areas may decline if drilling results are unsuccessful.
We have limited control over the activities on properties we do not operate.
Some of the properties in which we have an ownership interest are operated by other companies and involve third-party working interest owners. As of December 31, 2020, non-operated properties represented 14% of our estimated proved developed reserves, 10% of our estimated proved undeveloped reserves, and 12% of our estimated total proved reserves. We have limited ability to influence or control the operations or future development of non-operated properties, including the marketing of oil and gas production, compliance with environmental, occupational safety and health and other regulations, or the amount of expenditures required to fund the development and operation of such properties. Moreover, we are dependent on other working interest owners on these projects to fund their contractual share of capital and operating expenditures. These limitations and our dependence on the operators and other working interest owners for these projects could cause us to incur unexpected future costs and could have a material adverse effect on our business, financial condition, results of operations and cash flows.
We may be subject to risks in connection with acquisitions, divestitures, and joint development arrangements.
As part of our business strategy, we have made and will likely continue to make acquisitions of oil and gas properties, divest assets, and enter into joint development arrangements. The successful acquisition of producing properties requires an assessment of several factors, including but not limited to:
•future crude oil and natural gas prices and location and quality differentials;
•the quality of the title to acquired properties;
•future development costs, operating costs and property taxes; and
•potential environmental and other liabilities.
The accuracy of these acquisition assessments is inherently uncertain. In connection with these assessments, we perform a review, which we believe to be generally consistent with industry practices, of the subject properties. Our review will not reveal all existing or potential problems nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities prior to acquisition. Inspections may not always be performed on every property, and environmental problems are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller of the subject properties may be unwilling or unable to provide effective contractual protection against all or part of the problems. We sometimes are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
In addition, from time to time we may sell or otherwise dispose of certain assets as a result of an evaluation of our asset portfolio or to provide cash flow for use in reducing debt and enhancing liquidity. Such divestitures have inherent risks, including possible delays in closing, the risk of lower-than-expected sales proceeds for the disposed assets, and potential post-closing adjustments and claims for indemnification. Additionally, volatility and unpredictability in commodity prices may result in fewer potential bidders, unsuccessful sales efforts, and a higher risk that buyers may seek to terminate a transaction prior to closing. The occurrence of any of the matters described above could have an adverse impact on our business, financial condition, results of operations and cash flows.
Volatility in the financial markets or in global economic conditions, including consequences resulting from domestic political uncertainty, geopolitical events, international trade disputes and tariffs, and health epidemics could adversely impact our business.
United States and global economies may experience periods of volatility and uncertainty from time to time, resulting in unstable consumer confidence, diminished consumer demand and spending, diminished liquidity and credit availability, and inability to access capital markets. In recent years, certain global economies have experienced periods of political uncertainty, slowing economic growth, rising interest rates, changing economic sanctions, health-related concerns, and currency volatility. These global macroeconomic conditions may have a negative impact on commodity prices and the availability and cost of materials used in our industry, which in turn could have a material adverse effect on our business, financial condition, results of operations and cash flows.
In recent years, the United States government has initiated new tariffs on certain imported goods and has imposed increases to certain existing tariffs on imported goods. In response, certain foreign governments, most notably China, imposed retaliatory tariffs on certain goods their countries import from the United States. These and other events, including the United Kingdom's withdrawal from the European Union and the COVID-19 pandemic, have contributed to increased uncertainty for domestic and global economies. Additionally, growing trends toward populism and political polarization globally and in the U.S. have resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations, and government energy policies, which could pose a potential threat to domestic and global economic growth.
Trade restrictions or other governmental actions related to tariffs or trade policies have impacted, and have the potential to further impact, our business and industry by increasing the cost of materials used in various aspects of upstream, midstream, and downstream oil and gas activities. Furthermore, tariffs and any quantitative import restrictions, particularly those impacting the cost and availability of steel and aluminum, may cause disruption in the energy industry’s supply chain, resulting in the delay or cessation of drilling and completion efforts or the postponement or cancellation of new pipeline transportation projects the U.S. industry is relying on to transport its onshore production to market, as well as endangering U.S. liquefied natural gas export projects resulting in negative impacts on natural gas production. Additionally, trade and/or tariff disputes have impacted, and have the potential to further impact, domestic and global economies overall, which could result in reduced demand for crude oil and natural gas. Any of the above consequences could have a material adverse effect on our business, financial condition, results of operations and cash flows.
A cyber incident could result in information theft, data corruption, operational disruption, and/or financial loss.
Our business and industry has become increasingly dependent on digital technologies to conduct day-to-day operations including certain exploration, development and production activities. We rely heavily on digital technologies, including information systems and related infrastructure as well as cloud applications and services, to process and record financial and operating data; analyze seismic, drilling, completion and production information; manage production equipment; conduct reservoir modeling and reserves estimation; communicate with employees and business associates; perform compliance reporting and many other activities. The availability and integrity of these systems are essential for us to conduct our operations. Our business associates, including employees, vendors, service providers, financial institutions, and transporters, processors, and purchasers of our production are also heavily dependent on digital technology.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. Our technologies, systems, networks, and those of our business associates have been and continue to be the target of cyber attacks or information security breaches, which could lead to disruptions in critical systems, unauthorized release or theft of confidential or protected information, corruption of data or other disruptions of our business operations. In addition, certain cyber incidents, such as surveillance of our systems and those of our business associates, may remain undetected for an extended period.
A cyber attack involving our information systems and related infrastructure, and/or that of our business associates, could disrupt our business and negatively impact our operations in a variety of ways, including but not limited to unauthorized access to, or theft of, sensitive or proprietary information and data corruption or operational disruption that adversely affects our ability to carry on our business. Any such event could damage our reputation and lead to financial losses from remedial actions, loss of business, or potential liability, which could have a material adverse effect on our business, financial condition, results of operations or cash flows.
While the Company has established cyber security systems and controls, disclosure controls and procedures and incident response protocols, these systems, controls, procedures and protocols may not identify all risks and threats we face, or may fail to protect data or mitigate the adverse effects of data loss. To our knowledge we have not experienced any material losses relating to cyber attacks; however, there can be no assurance that we will not suffer material losses in the future either as a result of a breach of our systems or those of our business associates. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which may impose significant costs that are likely to increase over time.
Competition in the crude oil and natural gas industry is intense, making it more difficult for us to acquire properties, market crude oil and natural gas and secure trained personnel.
Our ability to acquire additional prospects and find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment for acquiring properties, securing long-term transportation and processing capacity, marketing crude oil and natural gas, and securing trained personnel. Also, there is substantial competition for capital available for investment in the crude oil and natural gas industry. Our competitors may possess and employ financial, technical and personnel resources greater than ours. Those companies may be able to pay more for productive crude oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. Our inability to effectively compete in this environment could have a material adverse effect on our financial condition, results of operations and cash flows.
Severe weather events and natural disasters could have a material adverse effect on our business, financial condition, results of operations and cash flows.
Severe weather events and natural disasters such as hurricanes, tornadoes, seismic events, floods, blizzards, extreme cold, drought, and ice storms affecting the areas in which we operate, including our corporate headquarters, could have a material adverse effect on our operations or the operations of third party service providers. The consequences of such events may include the evacuation of personnel; damage to and disruption of drilling rigs or transportation, processing, storage, refining, and export facilities; the shut-in of production resulting from an inability to transport crude oil or natural gas products to market centers and other factors; an inability to access well sites; destruction of information and communication systems; and the disruption of administrative and management processes, any of which could hinder our ability to conduct normal operations and could adversely affect our business, financial condition, results of operations or cash flows.
Terrorist activities could materially and adversely affect our business and results of operations.
Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign attacks, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued hostilities abroad and the occurrence or threat of terrorist attacks in the United States or other countries could adversely affect the global economy in unpredictable ways, including the disruption of energy supplies and markets, increased volatility in commodity prices or the possibility that infrastructure we rely on could be a direct target or an indirect casualty of an act of terrorism. Any of these events could materially and adversely affect our business and results of operations.
Our derivative activities could result in financial losses or reduce our earnings.
To achieve more predictable cash flows and reduce our exposure to adverse fluctuations in commodity prices, from time to time we may enter into derivative instruments for a potentially significant portion of our production. See Part II, Item 8. Notes to Consolidated Financial Statements—Note 5. Derivative Instruments for a summary of our commodity derivative positions as of December 31, 2020. Additionally, see Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Derivative Instruments for a summary of additional derivative instruments entered into subsequent to December 31, 2020. We do not designate our derivative instruments as hedges for accounting purposes and we record all derivatives on our balance sheet at fair value. Changes in the fair value of derivatives are recognized in earnings. Accordingly, our earnings may fluctuate materially as a result of changes in commodity prices and resulting changes in the fair value of any outstanding derivatives.
Derivative instruments expose us to the risk of financial loss in certain circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•the counterparty to the derivative instrument defaults on its contractual obligations; or
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received.
In addition, derivative arrangements limit the benefit we would otherwise receive from increases in commodity prices. Our decision on the quantity and price at which we choose to hedge our future production is based in part on our view of current and future market conditions and our desire to stabilize cash flows necessary for the development of our proved reserves. We may choose not to hedge future production if the pricing environment for certain time periods is deemed to be unfavorable. Additionally, we may choose to liquidate derivative positions prior to the expiration of their contractual maturities in order to monetize gain positions for the purpose of funding our capital program or other business opportunities.
Our revolving credit facility and indentures for our senior notes contain certain covenants and restrictions that may inhibit our ability to make certain investments, incur additional indebtedness and engage in certain other transactions, which could adversely affect our ability to meet our goals.
Our revolving credit facility contains restrictive covenants that may limit our ability to, among other things, incur additional indebtedness, incur liens, engage in sale and leaseback transactions, and merge, consolidate or sell all or substantially all of our assets. Our revolving credit facility also contains a requirement that we maintain a consolidated net debt to total capitalization ratio of no greater than 0.65 to 1.00. This ratio represents the ratio of net debt (calculated as total face value of debt plus outstanding letters of credit less cash and cash equivalents) divided by the sum of net debt plus total shareholders’ equity plus, to the extent resulting in a reduction of total shareholders’ equity, the amount of any non-cash impairment charges incurred, net of any tax effect, after June 30, 2014. At December 31, 2020, we had $160 million of outstanding borrowings on our credit facility and our consolidated net debt to total capitalization ratio, as defined, was 0.42 to 1.00.
The indentures governing our senior notes contain covenants that, among other things, limit our ability to create liens securing certain indebtedness, enter into certain sale and leaseback transactions, and consolidate, merge or transfer certain assets.
The covenants in our revolving credit facility and senior note indentures may restrict our ability to expand or pursue our business strategies. Our ability to comply with the provisions of our revolving credit facility or senior note indentures may be impacted by changes in economic or business conditions, results of operations, or events beyond our control. The breach of any covenant could result in a default under our revolving credit facility or senior note indentures, in which case, depending on the actions taken by the lenders or trustees thereunder or their successors or assignees, could result in all amounts outstanding thereunder, together with accrued interest, to be due and payable. If our indebtedness is accelerated, our assets may not be sufficient to repay in full such indebtedness, which would have a material adverse effect our business, financial condition, results of operations, and cash flows.
The inability of joint interest owners, significant customers, and service providers to meet their obligations to us may adversely affect our financial results.
Our principal exposure to credit risk is through the sale of our crude oil and natural gas production, which we market to energy marketing companies, crude oil refining companies, and natural gas gathering and processing companies ($561 million in receivables at December 31, 2020) and our joint interest and other receivables ($144 million at December 31, 2020). These counterparties may experience insolvency or liquidity issues and may not be able to meet their obligations and liabilities owed to us, particularly during a period of depressed commodity prices. Defaults by these counterparties could adversely impact our financial condition and results of operations.
Additionally, we rely on field service companies and midstream companies for services associated with the drilling and completion of wells and for certain midstream services. A worsening of the commodity price environment may result in a material adverse impact on the liquidity and financial position of the parties with whom we do business, resulting in delays in payment of, or non-payment of, amounts owed to us, delays in operations, loss of access to equipment and facilities and similar impacts. These events could have an adverse impact on our business, financial condition, results of operations and cash flows.
Legal and Regulatory Risks
Laws, regulations, guidance, executive actions or other regulatory initiatives regarding environmental protection and occupational safety and health could increase our costs of doing business and result in operating restrictions, delays, or cancellations in the drilling and completion of crude oil and natural gas wells, which could have a material adverse effect on our business, results of operations, financial condition and cash flows.
Our crude oil and natural gas exploration and production operations are subject to stringent federal, state and local legal requirements governing environmental protection and occupational safety and health. These requirements may take the form of laws, regulations, executive actions and various other legal initiatives. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for a discussion of those environmental and occupational safety and health legal requirements that govern us, including with respect to air emissions, including natural gas flaring limitations and ozone standards; climate change, including restriction of methane or other greenhouse gas emissions and suspensions of new leasing and permitting on federal lands and waters; elimination of subsidies for the oil and gas sector; hydraulic fracturing; waste water disposal regulatory developments; occupational safety standards, and other risks or regulations relating to environmental protection. One or more of these legal requirements could have a material adverse effect on our business, financial condition, results of operations, and cash flows.
We are subject to certain complex federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health that could result in increased costs, operating restrictions or delays, limitations or prohibitions on our ability to develop and produce reserves, or expose us to significant liabilities.
Our crude oil and natural gas exploration and production operations are subject to complex and stringent federal, state and local laws and regulations in areas other than environmental protection and occupational safety and health, including with respect to production, sales and transport of crude oil, NGLs and natural gas, and employees and labor relations. Following is a discussion of certain significant laws, rules and regulations that affect us in these areas in which we operate. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion of the regulations that affect us.
Taxation of oil and gas activities—In previous years, legislation has been proposed to eliminate or defer certain key U.S. federal income tax deductions historically available to oil and gas exploration and production companies. Such proposed changes have included: (i) a repeal of the percentage depletion allowance for crude oil and natural gas properties; (ii) the elimination of deductions for intangible drilling and exploration and development costs; (iii) the elimination of the deduction for certain production activities; and (iv) an extension of the amortization period for certain geological and geophysical expenditures. With President Biden taking office and the control of Congress shifting in January 2021, there is an increased risk of the enactment of legislation that alters, eliminates, or defers these or other tax deductions utilized within our industry, which could adversely affect our business, financial condition, results of operations and cash flows.
Dodd-Frank Act derivative regulations—In 2010, the U.S. Congress adopted the Dodd-Frank Act, which, among other provisions, established federal oversight and regulation of the over-the-counter derivatives market. If we do not qualify for an end user exemption from the Dodd-Frank Act requirements, the regulations could increase the cost of derivative contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize or restructure existing derivative contracts, lead to fewer potential counterparties, and increase our exposure to less creditworthy counterparties, any of which could limit our desire and ability to implement commodity price risk management strategies. Certain other regulations, including regulations related to capital requirements, which are yet to be implemented, may have an effect that results in the reduction of the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to us. If our use of derivatives becomes limited as a result of the regulations, our results of operations may become more volatile and our cash flows may be less predictable. Aspects of the Dodd-Frank rulemaking have been finalized in certain areas, but other areas have not been finalized or implemented and the ultimate effect of these regulations on our business remains uncertain.
Failure to comply with the above and other laws and regulations may trigger a variety of administrative, civil and criminal enforcement investigations or actions, including investigatory actions, the assessment of monetary penalties, the imposition of remedial requirements, the issuance of orders or judgments limiting or enjoining future operations, criminal sanctions, or litigation. Moreover, changes to existing laws or regulations or changes in interpretations of laws and regulations may
unfavorably impact us or the infrastructure used for transporting our products. Similarly, changes in regulatory policies and priorities, including those in response to the January 2021 change in U.S. presidential administrations and shift in control of Congress, could result in the imposition of new laws or regulations that adversely impact us or our industry. Any such changes could increase our operating costs, delay our operations or otherwise alter the way we conduct our business, which could have a material adverse effect on our financial condition, results of operations and cash flows.
Climate change activism, energy conservation measures, or initiatives that stimulate demand for alternative forms of energy could reduce the demand for the crude oil and natural gas we produce.
Climate change activism, fuel conservation measures, governmental requirements for renewable energy resources, increasing consumer demand for alternative forms of energy, and technological advances in fuel economy and energy generation devices may create new competitive conditions that result in reduced demand for the crude oil and natural gas we produce. The potential impact of changing demand for crude oil and natural gas services and products may have a material adverse effect on our business, financial condition, results of operations and cash flows. See Part I, Item 1. Business—Regulation of the Crude Oil and Natural Gas Industry for further discussion relating to climate change and emission of greenhouse gases, climate change activism, energy conservation measures or initiatives that stimulate demand for alternative forms of energy. One or more of these developments could have an adverse effect on our assets and operations.
We are involved in legal proceedings that could result in substantial liabilities.
Like other similarly-situated oil and gas companies, we are, from time to time, involved in various legal proceedings in the ordinary course of business including, but not limited to, commercial disputes, claims from royalty and surface owners, property damage claims, personal injury claims, regulatory compliance matters, disputes with tax authorities, and other matters. The outcome of such legal matters often cannot be predicted with certainty. We vigorously defend ourselves in all such matters. However, if our efforts to defend ourselves are not successful, it is possible the outcome of one or more such proceedings could result in substantial liability, penalties, sanctions, judgments, consent decrees, or orders requiring a change in our business practices, which could have a material adverse on our business, financial condition, results of operations and cash flows. Judgments and estimates to determine accruals related to legal and other proceedings could change from period to period, and such changes could be material.
Increasing attention to environmental, social, and corporate governance matters may impact our business.
Companies across all industries are facing increasing scrutiny from stakeholders related to their environmental, social, and corporate governance (“ESG”) practices. These standards are evolving and if we are perceived to have not responded appropriately to certain standards, regardless of whether there is a legal requirement to do so, we may suffer from reputational damage and our business, financial condition, and/or stock price could be materially and adversely affected. Increasing attention to climate change, increasing societal expectations on companies to address climate change, and potential consumer use of alternative forms of energy may result in increased costs, reduced demand for hydrocarbon products, reduced profits, increased investigations and litigation, and negative impacts on our stock price, our ability to recruit necessary talent, and our access to capital markets.
In addition, organizations that provide information to investors on corporate governance and related matters have developed ratings processes for evaluating companies on their approach to ESG matters. Currently, there are no universal standards for such scores or ratings and, in fact, different standards focus, to varying degrees, on different attributes of environmental, social, and corporate governance matters. This disparity between the “standards” may result in investors focusing on inadequate or improper metrics which may lead to a misperception of a company and its ESG practices. Nonetheless, the importance of sustainability evaluations is becoming more broadly accepted by investors and shareholders. ESG ratings are used by some investors to inform their investment and voting decisions. Additionally, certain investors use these scores to benchmark companies against their peers, and if a company is perceived as lagging, these investors may engage with companies to require improved ESG disclosure or performance. Moreover, certain members of the broader investment community may consider a company’s sustainability score as a reputational or other factor in making an investment decision. Consequently, a low sustainability score could result in exclusion of our stock from consideration by certain investment funds, engagement by investors seeking to improve such scores and a negative perception of our operations by certain investors.
Risks Related to our Corporate Structure
Our Executive Chairman beneficially owns approximately 81% of our outstanding common stock, giving him influence and control in corporate transactions and other matters, including a sale of our Company.
As of December 31, 2020, Harold G. Hamm, our Executive Chairman, beneficially owned approximately 81% of our outstanding common shares. As a result, Mr. Hamm has control over our Company and will continue to be able to control the
election of our directors, determine our corporate and management policies and determine, without the consent of our other shareholders, the outcome of certain corporate transactions or other matters submitted to our shareholders for approval, including potential mergers or acquisitions, asset sales and other significant corporate transactions. Therefore, Mr. Hamm could cause, delay or prevent a change of control of our Company. The interests of Mr. Hamm may not coincide with the interests of other holders of our common stock.
We have historically entered into, and may enter into, transactions from time to time with companies or persons affiliated with Mr. Hamm if, after an independent review by our Audit Committee or by the independent members of our Board of Directors, it is determined such transactions are in the Company’s best interests and are on terms no less favorable to us than could be achieved with an unaffiliated third party. These transactions may result in conflicts of interest between Mr. Hamm’s affiliated parties and us.
Item 1B. Unresolved Staff Comments
There were no unresolved Securities and Exchange Commission staff comments at December 31, 2020.
Item 2. Properties
The information required by Item 2 is contained in Part I, Item 1. Business—Crude Oil and Natural Gas Operations and Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations—Delivery Commitments and is incorporated herein by reference.
Item 3. Legal Proceedings
On April 15, 2020, Casillas Petroleum Resource Partners II, LLC filed a petition against the Company in the District Court of Tulsa County, State of Oklahoma alleging the Company breached a Purchase and Sale Agreement (“PSA”) to purchase oil and gas interests in Oklahoma for $200 million. The Company asserted the PSA was terminated due to Casillas’ breach of the PSA and denied the allegations. On October 16, 2020, the parties entered into a settlement agreement to amend and supplement the terms of the PSA, close on the transaction contemplated by the PSA for a negotiated amount, and settle all disputes involved in the litigation or that could have been raised in the litigation. The parties subsequently dismissed their respective claims in the litigation.
Item 4. Mine Safety Disclosures
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Our common stock is listed on the New York Stock Exchange and trades under the symbol “CLR.” As of January 29, 2021, the number of record holders of our common stock was 1,223. On January 29, 2021, after inquiry, management believes that the number of beneficial owners of our common stock is 55,192. On January 29, 2021, the last reported sales price of our common stock, as reported on the New York Stock Exchange, was $19.69 per share.
In May 2019, our Board of Directors approved the initiation of a dividend payment program and on June 3, 2019 the Company announced its first quarterly cash dividend of $0.05 per share, which was paid on November 21, 2019. On January 27, 2020 our Board of Directors approved a cash dividend of $0.05 per share for the first quarter of 2020, which was paid on February 21, 2020. To preserve cash in response to the significant reduction in crude oil prices and economic uncertainty resulting from the COVID-19 pandemic, in April 2020 the Company's quarterly dividend was suspended by the Board of Directors. Any payment of future dividends will be at the discretion of our Board of Directors and will depend on, among other things, our future earnings, financial condition, cash flows, capital requirements, levels of indebtedness, prevailing business conditions and other considerations our Board of Directors may deem relevant.
The following table provides information about purchases of our common stock during the quarter ended December 31, 2020:
|Period||Total number of shares purchased||Average price paid per share||Total number of shares purchased as part of publicly announced plans or programs (1)||Maximum dollar value of shares that may yet be purchased under the plans or programs (in millions) (1)|
|October 1, 2020 to October 31, 2020|
|Repurchases for tax withholdings (2)||9,292 ||$||12.40 ||— ||— |
|November 1, 2020 to November 30, 2020|
|Repurchases for tax withholdings (2)||11,297 ||$||14.06 ||— ||— |
|December 1, 2020 to December 31, 2020|
|Repurchases for tax withholdings (2)||— ||$||— ||— ||— |
|Total for the quarter||20,589 ||$||— ||— ||— |
(1)In May 2019 our Board of Directors approved the initiation of a share repurchase program to acquire up to $1 billion of our common stock beginning in June 2019 at times and levels deemed appropriate by management. The program was announced on June 3, 2019 and does not have a set expiration date. The share repurchase program may be modified, suspended, or terminated by our Board of Directors at any time. No share repurchases were made by the Company under the program during the three months ended December 31, 2020. The total dollar value of shares that may yet be purchased under the program totaled $682.9 million as of December 31, 2020.
(2)Amounts represent shares surrendered by employees to cover tax liabilities in connection with the vesting of restricted stock granted under the Company's 2013 Long-Term Incentive Plan. We paid the associated taxes to the applicable taxing authorities. The price paid per share was the closing price of our common stock on the date the restrictions lapsed on such shares.
Equity Compensation Plan Information
The following table sets forth the information as of December 31, 2020 relating to equity compensation plans:
|Number of Shares|
to be Issued Upon
Exercise Price of
Available for Future
Issuance Under Equity
Compensation Plans (1)
|Equity Compensation Plans Approved by Shareholders||— ||— ||10,768,301|
|Equity Compensation Plans Not Approved by Shareholders||— ||— ||— |
(1)Represents the remaining shares available for issuance under the 2013 Plan.
The following graph compares our common stock performance with the performance of the Standard & Poor’s 500 Stock Index (“S&P 500 Index”) and the Dow Jones US Oil and Gas Index (“Dow Jones US O&G Index”) for the period of December 31, 2015 through December 31, 2020. The graph assumes the value of the investment in our common stock and in each index was $100 on December 31, 2015 and that any dividends were reinvested. The stock performance shown on the graph below is not indicative of future price performance.
The information provided in this section is being furnished to, and not filed with, the SEC. As such, this information is neither subject to Regulation 14A or 14C nor to the liabilities of Section 18 of the Securities Exchange Act of 1934, as amended.
Item 6. Selected Financial Data
This section presents selected consolidated financial data for the years ended December 31, 2016 through 2020. The selected financial data presented below is not intended to replace our consolidated financial statements. The following financial data has been derived from our audited consolidated financial statements for such periods. You should read the following selected financial data in connection with Part II, Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations and our consolidated financial statements and related notes included elsewhere in this report. The selected consolidated results are not necessarily indicative of results to be expected in future periods. Operating and financial results attributable to noncontrolling interests are not material relative to the Company's consolidated results and are not separately presented below.
| ||Year Ended December 31,|
|Income Statement data|
|In thousands, except per share data|
|Crude oil and natural gas sales (1)||$||2,555,434 ||$||4,514,389 ||$||4,678,722 ||$||2,982,966 ||$||2,026,958 |
|Gain (loss) on derivative instruments, net||(14,658)||49,083 ||(23,930)||91,647 ||(71,859)|
|Total revenues ||2,586,470 ||4,631,947 ||4,709,586 ||3,120,828 ||1,980,273 |
|Net income (loss) (2)||(605,561)||774,473 ||989,700 ||789,447 ||(399,679)|
|Net income (loss) attributable to Continental Resources (2)(3)||(596,869)||775,641 ||988,317 ||789,447 ||(399,679)|
|Net income (loss) per share attributable to Continental Resources: (2)(3)|
|Basic||$||(1.65)||$||2.09 ||$||2.66 ||$||2.13 ||$||(1.08)|
|Diluted||$||(1.65)||$||2.08 ||$||2.64 ||$||2.11 ||$||(1.08)|
|Cash dividends per common share||$||0.05 ||$||0.05 ||— ||— ||— |
|Crude oil (MBbl)||58,745 ||72,267 ||61,384 ||50,536 ||46,850 |
|Natural gas (MMcf)||306,528 ||311,865 ||284,730 ||228,159 ||195,240 |
|Crude oil equivalents (MBoe)||109,833 ||124,244 ||108,839 ||88,562 ||79,390 |
|Average costs per unit|
|Production expenses ($/Boe)||$||3.27 ||$||3.58 ||$||3.59 ||$||3.66 ||$||3.65 |
|Production taxes (% of net oil and gas revenues)||8.2 ||%||8.3 ||%||7.9 ||%||7.0 ||%||7.0 ||%|
|DD&A ($/Boe)||$||17.12 ||$||16.25 ||$||17.09 ||$||18.89 ||$||21.54 |
|General and administrative expenses ($/Boe)||$||1.79 ||$||1.57 ||$||1.69 ||$||2.16 ||$||2.14 |
|Proved reserves at December 31|
|Crude oil (MBbl)||496,975 ||760,187 ||757,096 ||640,949 ||643,228 |
|Natural gas (MMcf)||3,640,724 ||5,154,471 ||4,591,614 ||4,140,281 ||3,789,818 |
|Crude oil equivalents (MBoe)||1,103,762 ||1,619,265 ||1,522,365 ||1,330,995 ||1,274,864 |
|Other financial data (in thousands)|