UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-K
For the fiscal year ended December 31 , 2021
or
Commission file number 001-37697
(Exact name of registrant as specified in its charter)
| (State of Incorporation) | (I.R.S. Employer Identification No.) | |||||||
(Registrant’s telephone number, including area code): (720 ) 499-1400
Securities registered pursuant to Section 12(b) of the Act:
| Title of each class | Trading Symbol(s) | Name of each exchange on which registered | ||||||||||||
Securities registered pursuant to Section 12(g) of the Act: None
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☒ No ☐
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☒
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to the filing requirements for the past 90 days. Yes ☒ No ☐
Indicate by check mark whether the Registrant has submitted electronically and posted on its corporate website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ☒ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company or an emerging growth company. (See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act).
| 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 Exchange Act). Yes ☐ No ☒
The aggregate market value of the voting and non-voting common stock held by non-affiliates of the registrant as of June 30, 2021, the last business day of the registrant’s most recently completed second fiscal quarter, was approximately $1,210,546,531 based on the closing price of the shares of common stock on that date.
As of February 18, 2022, there were 284,810,188 shares of Class A Common Stock, par value $0.0001 per share outstanding.
Documents Incorporated by Reference:
TABLE OF CONTENTS
| Page | ||||||||||||||
GLOSSARY OF OIL AND NATURAL GAS TERMS
The following are abbreviations and definitions of certain terms used in this Annual Report on Form 10-K, which are commonly used in the oil and natural gas industry:
Bbl. One stock tank barrel of 42 U.S. gallons liquid volume used herein in reference to crude oil, condensate or NGLs.
Bbl/d. One Bbl per day.
Boe. One barrel of oil equivalent, calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Bbl of oil. This is an energy content correlation and does not reflect a value or price relationship between the commodities.
Boe/d. One Boe per day.
Btu. One British thermal unit, which is the quantity of heat required to raise the temperature of a one-pound mass of water by one-degree Fahrenheit.
Completion. The process of preparing an oil and gas wellbore for production through the installation of permanent production equipment, as well as perforation and fracture stimulation to initiate production.
Development well. A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.
Differential. An adjustment to the price of oil or natural gas from an established spot market price to reflect differences in the quality and location of oil or natural gas.
Exploratory well. A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or natural gas in another reservoir.
Extension well. A well drilled to extend the limits of a known reservoir.
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.
Horizontal drilling. A drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at a right angle within a specified interval.
ICE Brent. Brent crude oil traded on the Intercontinental Exchange, Inc. (ICE).
LIBOR. London Interbank Offered Rate.
MBbl. One thousand barrels of crude oil, condensate or NGLs.
MBoe. One thousand Boe.
Mcf. One thousand cubic feet of natural gas.
Mcf/d. One Mcf per day.
MMBtu. One million British thermal units.
MMcf. One million cubic feet of natural gas.
NEOs. Named executive officers, which term refers to the principal executive officer, the principal financial officer, and the next three most highly paid executive officers of a company as of the end of the most recently completed fiscal year, based on total compensation as determined under Rule 402 of Regulation S-K.
NGL. Natural gas liquids. These are naturally occurring substances found in natural gas, including ethane, butane, isobutane, propane and natural gasoline, that can be collectively removed from produced natural gas, separated in these substances and sold.
NYMEX. The New York Mercantile Exchange.
Operator. The individual or company responsible for the development and/or production of an oil or natural gas well or lease.
Proved developed reserves. Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared with the cost of a new well.
3
Proved reserves. The estimated quantities of oil, NGLs and natural gas that geological and engineering data demonstrate with reasonable certainty to be commercially recoverable in future years from known reservoirs under existing economic and operating conditions.
Proved undeveloped reserves or PUD. Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for completion.
Realized price. The cash market price less differentials.
Reserves. Estimated remaining quantities of oil and natural gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and natural gas or related substances to market and all permits and financing required to implement the project.
Reservoir. A porous and permeable underground formation containing a natural accumulation of producible oil and/or natural gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
Royalty interest. An interest in an oil or gas property entitling the owner to shares of the production free of costs of exploration, development and production operations.
SOFR. Secured Overnight Funding Rate.
Spot market price. The cash market price without reduction for expected quality, location, transportation and demand adjustments.
Unproved reserves. Reserves attributable to unproved properties with no proved reserves.
Wellbore. The hole drilled by a drill bit that is equipped for oil and natural gas production once the well has been completed. Also called well or borehole.
Working interest. The interest in an oil and gas property (typically a leasehold interest) that gives the owner the right to drill, produce and conduct operations on the property and to a share of production, subject to all royalties and other burdens and to all costs of exploration, development and operations and all risks in connection therewith.
Workover. Operations on a producing well to restore or increase production.
WTI. West Texas Intermediate is a grade of crude oil used as a benchmark in oil pricing.
4
CAUTIONARY STATEMENT CONCERNING FORWARD-LOOKING STATEMENTS
This Annual Report on Form 10-K (the “Annual Report”), includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended (the “Securities Act”), and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). All statements, other than statements of historical fact included in this Annual Report, regarding our strategy, future operations, financial position, estimated revenues and losses, projected costs, prospects, plans and objectives of management are forward-looking statements. When used in this Annual Report, the words “could,” “may,” “believe,” “anticipate,” “intend,” “estimate,” “expect,” “project,” “goal,” “plan,” “target” and similar expressions are intended to identify forward-looking statements, although not all forward-looking statements contain such identifying words. These forward-looking statements are based on management’s current expectations and assumptions about future events and are based on currently available information as to the outcome and timing of future events. When considering forward-looking statements, you should keep in mind the risk factors and other cautionary statements described in Item 1A. Risk Factors in this Annual Report.
Forward-looking statements may include statements about:
•volatility of oil, natural gas and NGL prices or a prolonged period of low oil, natural gas or NGL prices and the effects of actions by, or disputes among or between, members of the Organization of Petroleum Exporting Countries (“OPEC”), such as Saudi Arabia, and other oil and natural gas producing countries, such as Russia, with respect to production levels or other matters related to the price of oil;
•the effects of excess supply of oil and natural gas resulting from the reduced demand caused by the Coronavirus Disease 2019 (“COVID-19”) pandemic and the actions by certain oil and natural gas producing countries;
•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;
•our business strategy and future drilling plans;
•our reserves and our ability to replace the reserves we produce through drilling and property acquisitions;
•our drilling prospects, inventories, projects and programs;
•our financial strategy, leverage, liquidity and capital required for our development program;
•our realized oil, natural gas and NGL prices;
•the timing and amount of our future production of oil, natural gas and NGLs;
•our hedging strategy and results;
•our competition and government regulations;
•our ability to obtain permits and governmental approvals;
•our pending legal or environmental matters;
•the marketing and transportation of our oil, natural gas and NGLs;
•our leasehold or business acquisitions;
•cost of developing or operating our properties;
•our anticipated rate of return;
•general economic conditions;
•weather conditions in the areas where we operate;
•credit markets;
•uncertainty regarding our future operating results; and
•our plans, objectives, expectations and intentions contained in this Annual Report that are not historical.
We caution you that these forward-looking statements are subject to all of the risks and uncertainties, most of which are difficult to predict and many of which are beyond our control, incident to the development, production, gathering and sale of oil and natural gas. These risks include, but are not limited to, commodity price volatility, inflation, lack of availability of drilling and production equipment and services, environmental risks, drilling and other operating risks, regulatory changes, the uncertainty inherent in estimating reserves and in projecting future rates of production, cash flow and access to capital, the timing of development expenditures and the other risks described in Item 1A. Risk Factors in this Annual Report.
5
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and price and cost assumptions made by reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ significantly from the quantities of oil and natural gas that are ultimately recovered.
Should one or more of the risks or uncertainties described in this Annual Report occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements.
All forward-looking statements, expressed or implied, included in this Annual Report are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.
Except as otherwise required by applicable law, we disclaim any duty to update any forward-looking statements, all of which are expressly qualified by the statements in this section, to reflect events or circumstances after the date of this Annual Report.
6
PART I
ITEMS 1 AND 2. BUSINESS AND PROPERTIES
Overview
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of crude oil and associated liquids-rich natural gas reserves in the Permian Basin. Throughout this Annual Report, unless the context otherwise indicates, references to the “Company,” “Centennial,” “we,” “us,” or “our” refer to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Our principal business objective is to increase shareholder value by efficiently developing our oil and natural gas assets in the Delaware Basin in an environmentally and socially responsible way. We intend to drive disciplined production growth through an increased focus on optimizing drilling and completion results, by drilling extended laterals, and by managing our costs, with an overall objective of improving our rates of return and generating sustainable free cash flow. We believe that the successful execution of these objectives will allow us to fund our drilling and development capex entirely from cash flows from operations, to lower our leverage profile and to return capital to our shareholders. We also look for opportunities to accretively increase scale and grow production and reserves through selective acquisitions that meet our strategic and financial objectives.
Organizational Structure
On October 11, 2016, the acquisition of approximately 89% of the outstanding membership interests in CRP was consummated (the “Business Combination”). CRP is currently a wholly-owned subsidiary of Centennial Resource Development due to various equity transactions.
The following diagram illustrates the current ownership structure of the company as of December 31, 2021, including the voting interests of our equity holders:
7
Description of Our Properties
Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and our properties consist of large, contiguous acreage blocks in West Texas and New Mexico. This continuity allows us to efficiently develop our drilling inventory and focus on maximizing returns to our stakeholders. We have established commercial production on our acreage using horizontal drilling from ten distinct zones: the Avalon Shale, 1st Bone Spring Sand, 2nd Bone Spring Sand, 2nd Bone Spring Shale, 3rd Bone Spring Sand, 3rd Bone Spring Shale, Upper Wolfcamp A, Lower Wolfcamp A, Wolfcamp B and Wolfcamp C. Our development drilling plan is comprised exclusively of horizontal drilling with an ongoing focus on operational execution and capital efficiency.
As of December 31, 2021, we have leased or acquired approximately 73,675 net acres, 97% of which we operate. In addition, we own 991 net mineral acres in the Delaware Basin. Approximately 66% of our total acreage is located in Texas, primarily Reeves County, in the southern portion of the Delaware Basin and the remaining 34% is located in Lea County, New Mexico, in the northern portion of the Delaware Basin. Over 96% of our net acreage is held by production as of December 31, 2021. The relatively high proportion of our operated acreage that is held by production gives us significant operational control and capital spending flexibility. This allows us to execute our development program with significant control over the timing and allocation of capital expenditures and application of the optimal drilling and completion techniques to efficiently develop our resource base as evidenced by our operational flexibility executed in 2021 and years passed.
8
Proved Oil and Gas Reserves
Reserve estimates are inherently imprecise, and estimates for new discoveries and undeveloped locations are more imprecise than reserve estimates for producing oil and gas properties. Accordingly, these estimates are expected to change as new information becomes available. The pre-tax PV 10% amounts shown in the following table are not intended to represent the current market value of our estimated proved reserves. The actual quantities and present value of our estimated proved reserves may be more or less than we have estimated, due to a number of factors. The following table should be read along with Item 1A. Risk Factors in this Annual Report.
The following table summarizes estimated proved reserves, pre-tax PV 10%, and standardized measure of discounted future cash flows for the periods indicated:
| December 31, 2021 | December 31, 2020 | December 31, 2019 | |||||||||||||||
| Proved developed reserves: | |||||||||||||||||
| Oil (MBbls) | 77,973 | 70,716 | 74,842 | ||||||||||||||
| Natural gas (MMcf) | 326,223 | 279,556 | 237,791 | ||||||||||||||
| NGL (MBbls) | 30,318 | 31,672 | 32,743 | ||||||||||||||
Total proved developed reserves (MBoe)(1) | 162,662 | 148,981 | 147,216 | ||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||
| Oil (MBbls) | 75,480 | 79,776 | 75,317 | ||||||||||||||
| Natural gas (MMcf) | 250,782 | 248,231 | 264,639 | ||||||||||||||
| NGL (MBbls) | 25,265 | 28,773 | 34,499 | ||||||||||||||
Total proved undeveloped reserves (MBoe)(1) | 142,542 | 149,921 | 153,923 | ||||||||||||||
| Total proved reserves: | |||||||||||||||||
| Oil (MBbls) | 153,453 | 150,492 | 150,159 | ||||||||||||||
| Natural gas (MMcf) | 577,005 | 527,787 | 502,430 | ||||||||||||||
| NGL (MBbls) | 55,583 | 60,445 | 67,242 | ||||||||||||||
Total proved reserves (MBoe)(1) | 305,204 | 298,902 | 301,139 | ||||||||||||||
| Proved developed reserves % | 53 | % | 50 | % | 49 | % | |||||||||||
| Proved undeveloped reserves % | 47 | % | 50 | % | 51 | % | |||||||||||
| Reserve values (in millions): | |||||||||||||||||
| Standard measure of discounted future net cash flows | $ | 3,396.3 | $ | 1,184.7 | $ | 2,062.4 | |||||||||||
| Discounted future income tax expense | 481.2 | 4.4 | 135.5 | ||||||||||||||
Total proved pre-tax PV 10%(2) | $ | 3,877.5 | $ | 1,189.1 | $ | 2,197.9 | |||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
(2) Total proved pre-tax PV 10% (“Pre-tax PV 10%”) is a supplemental non-GAAP financial measure as defined by the SEC and is derived from the standardized measure of discounted future net cash flows (the ‘‘Standardized Measure’’), which is the most directly comparable U.S. generally accepted accounting principles (“GAAP”) financial measure. Pre-tax PV 10% is computed on the same basis as the Standardized Measure but without deducting future income taxes. We believe Pre-tax PV 10% is a useful measure for investors when evaluating the relative monetary significance of our oil and natural gas properties. We further believe investors may utilize our Pre-tax PV 10% as a basis for comparison of the relative size and value of our proved reserves to other companies because many factors that are unique to each individual company impact the amount of future income taxes to be paid. Our management uses this measure when assessing the potential return on investment related to our oil and gas properties and acquisitions. However, Pre-tax PV 10% is not a substitute for the Standardized Measure. Our Pre-tax PV 10% and Standardized Measure do not purport to present the fair value of our proved oil, NGL and natural gas reserves.
9
Proved Undeveloped Reserves. Our proved undeveloped (“PUD”) reserves decreased by 7.4 MMBoe on a net basis from December 31, 2020 to December 31, 2021, and the following table provides a reconciliation of the changes to our PUD reserves that occurred during the year:
| (MBoe) | 2021 | ||||
| Proved undeveloped reserves at January 1, | 149,921 | ||||
| Transferred to proved developed reserves | (30,968) | ||||
| Revisions to previous estimates | (6,423) | ||||
| Extensions and discoveries | 30,012 | ||||
| Proved undeveloped reserves at December 31, | 142,542 | ||||
We spent $224.2 million in capital expenditures to convert 31.0 MMBoe of PUD reserves to proved developed reserves during 2021. We added 30.0 MMBoe of PUD reserves during the year through extensions and discoveries, which mainly related to new locations added based on our 2021 drilling results. The majority of these new PUD locations were on our New Mexico acreage within the various Bone Spring Sand formations, and we also added locations in the Wolfcamp C on our Texas acreage position. Total revisions to previous estimates reduced PUD reserves by a net amount of 6.4 MMBoe. Negative revisions during 2021 totaled 22.0 MMBoe and mainly related to PUD locations that were either reclassified to unproved reserves or removed due to changes in our active drilling program. These downward revisions were partially offset by 15.6 MMBoe of positive revisions primarily related to upward pricing adjustments associated with higher average commodity prices for the year ended December 31, 2021. All of our PUD locations are scheduled to be drilled within five years of their initial booking. Our PUD to proved developed reserves conversion rate was 20% in 2021.
For additional information and for a discussion of material changes on our total proved reserves, see Supplemental Information About Oil & Natural Gas Producing Activities, Item 8. Financial Statements and Supplementary Data of this Annual Report.
Preparation of Reserve Estimates
Our proved reserves are estimated by an independent engineering firm, Netherland, Sewell & Associates, Inc. (“NSAI”). Reserve estimates are prepared in accordance with the definitions and regulations of the SEC and the Financial Accounting Standards Board (the “FASB”) using a deterministic method, which includes decline curve analysis, production performance analysis, offset analogies, and in some cases a combination of these methodologies.
Controls over Reserve Estimation
We maintain adequate and effective internal controls over the reserve estimation process and the underlying data which the reserve estimates are based upon. Our reserves estimation process is coordinated by our internal reserves department, which consists of qualified petroleum engineers, and is overseen by our Vice President of Strategic Planning and Corporate Reserves. Reserve information, including models and other technical data, are stored on a secured database on our network. Certain non-technical inputs used in the reserves estimation process such as ownership interest percentages, oil and natural gas production, commodity prices, price differentials, operating and development costs and plug and abandonment estimates are obtained by other departments and are subject to our internal control process. Annually, our internal reserves department prepares a preliminary reserve database and meets with NSAI to discuss the assumptions and methods to be used in the year-end proved reserve estimation process and to review field performance and our future development plans. Following this review, the reserve database and supporting data is furnished to NSAI for their independent estimates and final report.
Qualifications of Responsible Technical Persons
Our Vice President of Strategic Planning and Corporate Reserves, Jeff Thompson, is responsible for overseeing the preparation of the reserves estimates. Mr. Thompson has held this position at Centennial since July 2017 and has over 15 years of relevant experience in reservoir engineering and reserve estimation. He holds a Bachelor of Science degree in petroleum engineering from the University of Oklahoma.
NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical persons primarily responsible for preparing the estimates set forth in the NSAI reserve report incorporated herein are Mr. Neil H. Little and Mr. Edward C. Roy III. Mr. Little, a Licensed Professional Engineer in the State of Texas (No. 117966), has been practicing petroleum engineering at NSAI since 2011 and has over 9 years of prior industry experience. He graduated from Rice University in 2002 with a Bachelor of Science Degree in Chemical Engineering and from the University of Houston in 2007 with a Master of Business Administration Degree. Mr. Roy, a Licensed Professional Geoscientist in the State of Texas, Geology (No. 2364), has been practicing consulting petroleum geoscience at NSAI since 2008 and has over 11 years of prior industry experience. He graduated from Texas Christian University
10
in 1992 with a Bachelor of Science Degree in Geology and from Texas A&M University in 1998 with a Master’s Degree in Geology. Both technical principals meet or exceed the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; both are proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
Production
The following table sets forth information regarding net production of oil, natural gas and NGLs, and certain price and cost information for each of the periods indicated:
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Net production: | |||||||||||||||||
| Oil (MBbls) | 11,701 | 13,207 | 15,582 | ||||||||||||||
| Natural gas (MMcf) | 40,741 | 41,302 | 41,703 | ||||||||||||||
| NGL (MBbls) | 3,752 | 4,490 | 5,234 | ||||||||||||||
Total (MBoe)(1) | 22,243 | 24,581 | 27,766 | ||||||||||||||
| Average sales price (excluding effect of hedges): | |||||||||||||||||
| Oil (per Bbl) | $ | 63.50 | $ | 36.02 | $ | 52.02 | |||||||||||
| Natural gas (per Mcf) | 3.67 | 1.13 | 1.07 | ||||||||||||||
| NGL (per Bbl) | 36.61 | 12.91 | 17.03 | ||||||||||||||
Total per BOE(1) | $ | 46.30 | $ | 23.61 | $ | 34.01 | |||||||||||
| Operating costs per Boe: | |||||||||||||||||
| Lease operating expenses | $ | 4.78 | $ | 4.45 | $ | 5.26 | |||||||||||
| Severance and ad valorem taxes | 3.02 | 1.60 | 2.28 | ||||||||||||||
| Gathering, processing and transportation expenses | 3.86 | 2.90 | 2.62 | ||||||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Productive Wells
As of December 31, 2021, we owned an approximate 75% average working interest in 540 gross (404 net) productive wells. Our wells are primarily oil wells (526 gross/393 net productive oil wells) that produce associated liquids-rich natural gas. Productive wells consist of producing wells, wells capable of production and wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, operated and non-operated, and net wells are the sum of our fractional working interests owned in gross wells.
Acreage
The following table sets forth information as of December 31, 2021 relating to our gross and net developed and undeveloped leasehold acreage. Developed acreage consists of acres spaced or assigned to productive wells and does not include undrilled acreage held by production under the terms of the lease. Undeveloped acreage is defined as acres on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or natural gas, regardless of whether such acreage contains proved reserves.
| Developed Acreage | Undeveloped Acreage | Total Acreage | ||||||||||||||||||||||||||||||
Gross(1) | Net(2) | Gross(1) | Net(2) | Gross(1) | Net(2) | |||||||||||||||||||||||||||
| 60,522 | 47,933 | 31,433 | 25,742 | 91,955 | 73,675 | |||||||||||||||||||||||||||
(1) A gross acre is an acre in which a working interest is owned. The number of gross acres is the total number of acres in which a working interest is owned.
(2) A net acre is deemed to exist when the sum of the fractional ownership working interests in gross acres equals one. The number of net acres is the sum of the fractional working interests owned in gross acres expressed as whole numbers and fractions thereof.
11
The following table sets forth the gross and net undeveloped acreage, as of December 31, 2021, that will expire over the next five years unless production is established within the spacing units covering the acreage, the lease is renewed or extended under continuous drilling provisions prior to the primary term expiration dates, or pursuant to other terms of the lease agreements.
| 2022 | 2023 | 2024 | 2025 | 2026 | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||||||||||||||||
| 2,821 | 1,748 | 320 | 29 | 1,205 | 938 | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
Drilling Results
The following table sets forth the results of our drilling activity, as defined by wells placed on production, for the periods indicated. Productive wells are exploratory, development or extension wells that produce, or are capable of producing, commercial quantities of hydrocarbons, regardless of whether they produce a reasonable rate of return. Dry wells are exploratory, development or extension wells that prove to be incapable of producing hydrocarbons in sufficient quantities to justify incurring the costs associated with completion as an oil or gas well.
| Year Ended December 31, | |||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||
| Development Wells: | |||||||||||||||||||||||||||||||||||
| Productive | 42 | 38.0 | 31 | 29.5 | 84 | 73.6 | |||||||||||||||||||||||||||||
Dry(1) | — | — | 1 | 1.0 | 2 | 2.0 | |||||||||||||||||||||||||||||
| 42 | 38.0 | 32 | 30.5 | 86 | 75.6 | ||||||||||||||||||||||||||||||
| Exploratory Wells: | |||||||||||||||||||||||||||||||||||
| Productive | — | — | — | — | — | — | |||||||||||||||||||||||||||||
| Dry | — | — | 1 | 1.0 | — | — | |||||||||||||||||||||||||||||
| — | — | 1 | 1.0 | — | — | ||||||||||||||||||||||||||||||
| Total | 42 | 38.0 | 33 | 31.5 | 86 | 75.6 | |||||||||||||||||||||||||||||
(1) The dry hole category includes wells that were unsuccessful due to mechanical issues that occurred during drilling.
As of December 31, 2021, we had 15 gross (12.8 net) operated wells in the process of drilling, completing or waiting on completion.
12
Delivery Commitments
The table below summarizes our firm sales agreements for crude oil and natural gas, both of which provide for gross firm sales over the contractual terms:
Oil Volume Commitments(1)(2) | Gas Volume Commitments(1)(3) | |||||||||||||||||||||||||
| Period | Total (Bbl) | Daily (Bbls/d) | Total (MMBtu) | Daily (MMBtu/d) | ||||||||||||||||||||||
| 2022 | 14,240,000 | 39,000 | 14,250,000 | 46,900 | ||||||||||||||||||||||
| 2023 | 16,060,000 | 44,000 | — | — | ||||||||||||||||||||||
| 2024 | 10,610,000 | 29,000 | — | — | ||||||||||||||||||||||
| 2025 | 4,380,000 | 29,000 | — | — | ||||||||||||||||||||||
| Total | 45,290,000 | 14,250,000 | ||||||||||||||||||||||||
(1) Above volumes represent the total gross volumes we are required to deliver pursuant to agreements with carriers, which gross volumes are not comparable to our net production presented in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation in this Annual Report, as amounts therein are reflected net of all royalties, overriding royalties and production due to others.
(2) The oil volume commitments listed above represent our total crude oil takeaway capacity that has been contracted with third party carriers. Of these total oil volumes committed, however, only 29,000 Bbls/d from January 2022 through May 2025 are subject to a financial ship-or-pay penalties if such physical delivery commitments are not met.
(3) We are not required to physically deliver these gross volumes over the terms of the agreements, but if the volumetric commitments are not met and the purchaser incurs financial damages, we are required to pay for any differences between the contracted prices and current market prices for replacement volumes bought by the purchaser.
We believe our current production and reserves are sufficient to fulfill these physical delivery commitments, and production under the agreements is not tied to any specific property. Therefore, if our production is not sufficient to satisfy the firm delivery commitments above, we believe we can purchase sufficient volumes in the market at index-related prices to satisfy our commitments. See also Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations — Contractual Obligations, in this Annual Report for discussion of our firm transportation commitments related to natural gas deliveries.
Title to Properties
We believe that we have satisfactory title to substantially all of our producing properties in accordance with generally accepted industry standards. Individual properties may be subject to burdens such as royalty, overriding royalty, working and other outstanding interests customary in the industry. In most cases, we investigate title and obtain title opinions from counsel only when we acquire producing properties or before commencement of drilling operations.
Marketing and Customers
We market the majority of the production from properties we operate on account of both ourselves and that of the other working interest owners in these properties. We generally sell our oil, natural gas and NGL production to purchasers at prevailing market prices, which in certain cases are adjusted for contractual differentials, and the majority of our revenue contracts have terms greater than twelve months.
We normally sell production to a relatively small number of customers, as is customary in our business. The table below summarizes the purchasers that accounted for 10% or more of our total net revenues for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| BP America | 50 | % | 47 | % | 37 | % | |||||||||||
| Shell Trading (US) Company | 22 | % | 20 | % | 11 | % | |||||||||||
| Eagleclaw Midstream Ventures, LLC | 11 | % | 8 | % | 8 | % | |||||||||||
| ExxonMobil Oil Corporation | — | % | 4 | % | 26 | % | |||||||||||
During these periods, no other purchaser accounted for 10% or more of our net revenues. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term. However, since crude oil and natural gas are fungible products with well-established markets and numerous purchasers and are based on current demand for oil and natural gas, we believe that the loss of any major purchaser would not have a material adverse effect on our financial condition or results of operations.
13
Competition
The oil and natural gas industry is a highly competitive environment. We compete with both major integrated and other independent oil and natural gas companies in all aspects of our business including exploring, developing and operating our properties as well as transporting and marketing our production. Competitive conditions may be affected by future legislation and regulations as the United States develops new energy and climate-related policies. In addition, some of our competitors may have a competitive advantage when responding to factors that affect the supply and demand for oil and natural gas production, such as price fluctuations (including basis differentials), domestic and foreign political conditions, weather conditions, the proximity and capacity of natural gas pipelines and other transportation facilities and overall economic conditions. We also face indirect competition from alternative energy sources. 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 in a highly competitive environment.
Transportation
During the initial development of our fields, we consider all gathering and delivery infrastructure options in the areas of our production. The majority of our oil production is sold at the lease as it enters third-party gathering pipelines. The purchaser then transports the oil by pipeline or truck to a tank farm, another pipeline or a refinery. Our natural gas is either transported by gathering lines from the wellhead to a central delivery point and is then gathered by third-party lines to a gas processing facility or gathered by a third-party directly from the wellhead.
Regulation of the Oil and Natural Gas Industry
Our operations are subject to extensive federal, state and local laws and regulations. All of the jurisdictions in which we own or operate producing properties have statutory provisions regulating the development and production of oil and natural gas, including, but not limited to, provisions related to permits for the drilling of wells, bonding requirements to drill or operate wells, the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled, sourcing and disposal of water used in the drilling and completion process, and the abandonment of wells. Our operations are also subject to various conservation laws and regulations including, but not limited to, the regulation of the size of drilling and spacing units or proration units, the number of wells which may be drilled in an area, and the unitization or pooling of crude oil or natural gas wells, as well as regulations that generally prohibit the venting or flaring of natural gas and impose certain requirements regarding the ratability or fair apportionment of production from fields and individual wells.
Failure to comply with applicable laws and regulations can result in substantial penalties. The regulatory burden on the industry increases the cost of doing business and affects profitability. Although we believe we are in substantial compliance with all applicable laws and regulations, such laws and regulations are frequently amended or reinterpreted. Therefore, we are unable to predict the future costs or impact of compliance. Additional proposals and proceedings affecting the oil and natural gas industry are regularly considered by Congress, the states, regulatory authorities, including the Federal Energy Regulatory Commission (“FERC”), and the courts. We cannot predict when or whether any such proposals may become effective.
We believe we are in substantial compliance with currently applicable laws and regulations and that continued substantial compliance with existing requirements will not have a material adverse effect on our financial position, cash flows or results of operations. However, current regulatory requirements may change, currently unforeseen environmental incidents may occur or past non-compliance with environmental laws or regulations may be discovered. In addition, governmental, scientific, and public concern over the threat of climate change arising from greenhouse gas (“GHG”) emissions has resulted in increasing political and regulatory risks in the United States, including climate change related pledges made by certain candidates elected to public office. President Biden has issued several executive orders focused on addressing climate change since taking office last year, including items that may impact the costs to produce, or demand for, oil and natural gas. Additionally, in November 2021, the Biden Administration released “The Long-Term Strategy of the United States: Pathways to Net-Zero Greenhouse Gas Emissions by 2050,” which establishes a roadmap to net zero emissions in the United States by 2050 through, among other things, improving energy efficiency; decarbonizing energy sources via electricity, hydrogen, and sustainable biofuels; and reducing non-carbon dioxide GHG emissions, such as methane and nitrous oxide. The Biden Administration is also considering revisions to the leasing and permitting programs for oil and natural gas development on federal lands.
Regulation of Production of Oil and Natural Gas
The production of oil, natural gas and NGLs is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. We own interests in properties located in New Mexico and Texas, which regulate drilling and operating activities by, among other things, requiring permits for the drilling of wells, maintaining bonding requirements in order to drill or operate wells, and regulating the location of wells, the method of drilling and casing wells, the surface use and restoration of properties upon which wells are drilled and the plugging and abandonment of wells. The laws of New Mexico and Texas also govern a number of conservation matters, including provisions for the unitization or pooling of oil and natural gas
14
properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing or density, and plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil, natural gas and NGLs that we can produce from our wells and to limit the number of wells or the locations where we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing or density. Moreover, New Mexico and Texas impose a production or severance tax with respect to the production and sale of oil, natural gas and NGLs within their jurisdiction.
Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations, and as a result we do not expect compliance with such regulatory requirements to affect our operations in any way that is of material difference from our competitors who are similarly situated. However, the failure to comply with these rules and regulations can result in substantial penalties.
Regulation of Sales and Transportation of Oil
Sales of oil, condensate and NGLs from our producing wells are not currently regulated and are made at negotiated prices. Nevertheless, Congress could enact price controls in the future.
Sales of oil are affected by the availability, terms and conditions and cost of transportation services. The transportation of oil in common carrier pipelines is also subject to rate and access regulation. FERC regulates the transportation in interstate commerce of crude oil, petroleum products, NGLs and other forms of liquid fuel under the Interstate Commerce Act.
Intrastate oil pipeline transportation rates are subject to regulation by state regulatory commissions. The basis for intrastate oil pipeline regulation, and the degree of regulatory oversight and scrutiny given to intrastate oil pipeline rates, varies from state to state. We rely on third-party pipeline systems to transport the majority of crude oil produced by ours wells. Insofar as effective interstate and intrastate rates and regulations regarding access are equally applicable to all comparable shippers, we believe that the regulation of oil transportation will not affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other oil producers and marketers with which we compete.
Regulation of Transportation and Sales of Natural Gas
Historically, the transportation and sale of natural gas in interstate commerce have been regulated by agencies of the U.S. federal government, primarily FERC. In the past, the federal government regulated the prices at which natural gas could be sold. While sales by producers of natural gas can currently be made at uncontrolled market prices, Congress could reenact price controls in the future. Deregulation of wellhead natural gas sales began with the enactment of the Natural Gas Policy Act of 1978 (the “NGPA”) and culminated in adoption of the Natural Gas Wellhead Decontrol Act, which removed controls affecting wellhead sales of natural gas effective January 1, 1993. The transportation and sale for resale of natural gas in interstate commerce is regulated primarily under the Natural Gas Act of 1938 (the “NGA”), and by regulations and orders promulgated under the NGA by FERC. In certain limited circumstances, intrastate transportation and wholesale sales of natural gas may also be affected directly or indirectly by laws enacted by Congress and by FERC regulations.
The federal Energy Policy Act of 2005 (the “EP Act of 2005”) is a comprehensive compilation of tax incentives, authorized appropriations for grants and guaranteed loans, and significant changes to the statutory policy that affects all segments of the energy industry. Among other matters, the EP Act of 2005 amended the NGA to add an anti-market manipulation provision that makes it unlawful for any entity to engage in prohibited behavior to be prescribed by FERC, and furthermore provides FERC with additional civil penalty authority. The EP Act of 2005 provided FERC with the power to assess civil penalties of up to $1.0 million per day for violations of the NGA and increased FERC’s civil penalty authority under the NGPA from $5,000 per violation per day to $1.0 million per violation per day. In January 2020, FERC issued a final rule increasing its maximum civil penalty authority under the NGA and NGPA to adjust for inflation. FERC may now assess civil penalties under the NGA and NGPA of $1,307,164 per violation per day. The civil penalty provisions are applicable to entities that engage in the sale of natural gas for resale in interstate commerce. On January 19, 2006, FERC issued Order No. 670, a rule implementing the anti-market manipulation provision of the EP Act of 2005, and subsequently denied rehearing. The rules make it unlawful, in connection with the purchase or sale of natural gas or the purchase or sale of transportation services subject to the jurisdiction of FERC, for any entity, directly or indirectly, to: (i) use or employ any device, scheme or artifice to defraud; (ii) make any untrue statement of material fact or omit to make any such statement necessary to make the statements made not misleading; or (iii) engage in any act or practice that operates as a fraud or deceit upon any person. The new anti-market manipulation rule does not apply to activities that relate only to intrastate or other non-jurisdictional sales or gathering, but does apply to activities of gas pipelines and storage companies that provide interstate services, as well as otherwise non-jurisdictional entities to the extent the activities are conducted “in connection with” gas sales, purchases or transportation subject to FERC jurisdiction, which now includes the annual reporting
15
requirements under Order 704, described below. The anti-market manipulation rule and enhanced civil penalty authority reflect an expansion of FERC’s NGA enforcement authority.
We are required to observe such anti-market manipulation laws and related regulations enforced by FERC under the EP Act of 2005 and those enforced by the US Commodity Futures Trading Commission (the “CFTC”) under the Commodity Exchange Act, as amended (the “CEA”) and CFTC regulations promulgated thereunder. The CEA prohibits any person from manipulating or attempting to manipulate the price of any commodity in interstate commerce, as well as the market for financial instruments on such commodity, such as futures, options and swaps. The CEA also prohibits knowingly delivering or causing to be delivered false or misleading or knowingly inaccurate reports concerning market information or conditions that affect or tend to affect the price of a commodity. Should we violate the anti-market manipulation laws and regulations, we could also be subject to related third-party damage claims by, among others, sellers, royalty owners and taxing authorities.
Natural gas gathering service, which occurs upstream of jurisdictional transmission services, is regulated by the states. Section 1(b) of the NGA exempts companies that provide natural gas gathering services from regulation by FERC as a “natural gas company” under the NGA. Although FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, FERC’s determinations as to the classification of facilities are done on a case-by-case basis. To the extent that FERC issues an order that reclassifies certain jurisdictional transmission facilities as non-jurisdictional gathering facilities, or vice versa, and depending on the scope of that decision, our costs of delivering gas to point-of-sale locations may increase. We believe that the natural gas pipelines in our gathering systems meet the traditional tests FERC has used to establish a pipeline’s status as a gatherer not subject to regulation as a natural gas company. However, the distinction between FERC-regulated transmission services and federally unregulated gathering services is the subject of ongoing litigation, so the classification and regulation of our gathering facilities are subject to change based on future determinations by FERC, the courts or Congress. State regulation of natural gas gathering facilities generally includes various occupational safety, environmental and, in some circumstances, nondiscriminatory-take requirements. Although such regulation has not generally been affirmatively applied by state agencies, natural gas gathering may receive greater regulatory scrutiny in the future.
Intrastate natural gas transportation is also subject to regulation by state regulatory agencies. 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 within the state on a comparable basis, we believe that the regulation of similarly situated intrastate natural gas transportation in any states in which we operate and ship natural gas on an intrastate basis will not affect our operations in any way that is of material difference from those of our competitors. Like the regulation of interstate transportation rates, the regulation of intrastate transportation rates affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas.
Changes in FERC or state policies and regulations or laws may adversely affect the availability and reliability of firm and/or interruptible transportation service on interstate and intrastate pipelines, and we cannot predict what future action that FERC or state regulatory bodies will take. We do not believe, however, that any regulatory changes will affect us in a way that materially differs from the way they will affect other natural gas producers and marketers with which we compete.
Regulation of Environmental and Occupational Safety and Health Matters
Our operations are subject to stringent federal, state and local laws and regulations governing the occupational safety and health aspects of our operations, the discharge of materials into the environment, and protection of the environment and natural resources (including threatened and endangered species and their habitats). Numerous governmental entities, including the U.S. Environmental Protection Agency (the “EPA”) and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them, often requiring difficult and costly actions. These laws and regulations may, among other things, (i) require the acquisition of permits to conduct drilling and other regulated activities; (ii) restrict the types, quantities and concentrations of various substances that can be released into the environment or injected into formations in connection with drilling and production activities; (iii) limit or prohibit drilling activities on certain lands lying within wilderness, wetlands, and other protected areas; (iv) require remedial measures to prevent or mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells; (v) apply specific health and safety criteria addressing worker protection; and (vi) impose substantial liabilities for pollution resulting from drilling and production operations. Any failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, the imposition of corrective or remedial obligations, the occurrence of delays or restrictions in permitting or performance of projects, and the issuance of orders enjoining performance of some or all of our operations.
The following is a summary of the more significant existing and proposed environmental and occupational safety and health laws, as amended from time to time, to which our business operations are or may be subject, and for which compliance may have a material adverse impact on our capital expenditures, results of operations or financial position.
16
Hazardous Substances and Handling Wastes
The Resource Conservation and Recovery Act (“RCRA”) and comparable state laws regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and nonhazardous solid wastes. Pursuant to rules issued by the EPA, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters and other wastes associated with the exploration, development and production of oil, natural gas and NGLs, if properly handled, are currently exempt from regulation as hazardous waste under RCRA and, instead, are regulated under RCRA’s less stringent nonhazardous solid waste provisions, state laws or other federal laws. However, it is possible that certain oil and natural gas drilling and production wastes now classified as nonhazardous solid wastes could be classified as hazardous wastes in the future. For example, in December 2016, the EPA and environmental groups entered into a consent decree to address the EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree required the EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes, or to sign a determination that revision of the regulations is not necessary. After undertaking its review, the EPA concluded in 2019 that it does not need to regulate exploration and production waste, and specifically "drilling fluids, produced waters, and other wastes associated with the exploration, development, or production of oil, gas or geothermal energy." The EPA concluded that states are adequately regulating exploration and production waste under the Subtitle D provisions of RCRA. However, any such change in the future could result in an increase in our, as well as the oil, natural gas and NGL exploration and production industry’s, costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. In addition, in the course of our operations, we may generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents, laboratory wastes and waste compressor oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics. Although the costs of managing hazardous waste may be significant, we do not believe that our costs in this regard are materially more burdensome than those for similarly situated companies.
The Comprehensive Environmental Response, Compensation, and Liability Act (“CERCLA”), also known as the Superfund law, and comparable state laws impose joint and several liability, without regard to fault or the legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current and former owners or operators of the site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources, and for the costs of certain health studies. CERCLA also authorizes the EPA and, in some instances, third parties to act in response to threats to the public health or the environment, and to seek to recover from the responsible classes of persons the costs they incur. In addition, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. We may generate materials in the course of our operations that may be regulated as hazardous substances.
We currently own, lease or operate numerous properties that have been used for oil, natural gas and NGL exploration, production and processing for many years. Although we believe that we have utilized operating and waste disposal practices that were standard in the industry at the time, hazardous substances, wastes, or petroleum hydrocarbons may have been released on, under or from the properties owned or leased by us, or on, under or from other locations, including off-site locations, where such substances have been taken for treatment or disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes or petroleum hydrocarbons was not under our control. These properties and the substances disposed or released on, under or from them may be subject to CERCLA, RCRA and analogous state laws. Under such laws, we could be required to undertake response or corrective measures, which could include removal of previously disposed substances and wastes, cleanup of contaminated property or performance of remedial plugging or pit closure operations to prevent future contamination, the costs of which could be substantial.
Water Discharges
The Clean Water Act (the “CWA”) and comparable state laws impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of hazardous substances, into state waters and waters of the United States. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or an analogous state agency. Spill prevention, control and countermeasure plan requirements imposed under the CWA require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. In addition, the CWA and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for noncompliance with discharge permits or other CWA requirements and analogous state laws and regulations.
17
The CWA also prohibits the discharge of dredge and fill material into regulated waters, including wetlands, unless authorized by permit. The EPA and the U.S. Army Corps of Engineers issued final rules attempting to clarify the federal jurisdictional reach over Waters of the United States in 2015 (the “WOTUS rule”). However, in 2017, President Trump issued an executive order directing the EPA and the U.S. Army Corps of Engineers to review the WOTUS rule and, if the agencies’ reviews find that the rule does not meet the executive order’s goal of promoting economic growth while reducing regulatory uncertainty, to initiate a new rulemaking to repeal or revise the rule. The EPA and the U.S. Army Corps of Engineers formally repealed the WOTUS rule in September 2019. In January 2020, the Trump administration published a final replacement rule, called the Navigable Waters Protection Rule, that purports to expressly define which categories of water may be federally regulated under the CWA. In addition, in an April 2020 decision defining the scope of the CWA, the U.S. Supreme Court held that, in certain cases, discharges from a point source to groundwater could fall within the scope of the CWA and require a permit. The U.S. Supreme Court rejected assertions by the EPA and the U.S. Army Corps of Engineers that groundwater should be totally excluded from CWA jurisdiction. In August 2021, a federal judge in the District of Arizona struck down the Navigable Waters Protection Rule. Soon after, the Biden administration and the U.S. Army Corps of Engineers announced that they have stopped enforcing the Navigable Waters Protection Rule nationwide and that they are reverting back to the 1986 WOTUS definition. In November 2021, the EPA and U.S. Army Corps of Engineers issued prepublication notice of a proposed rule to revise the definition of “waters of the United States” to put back into place the pre-2015 definition, updated to reflect consideration of Supreme Court decisions. As such, uncertainty remains with respect to future implementation of the rule.
The process for obtaining permits under the CWA also has the potential to impact our operations. In April 2020, the U.S. District Court for the District of Montana vacated Nationwide Permit (“NWP”) 12, the general permit issued by the U.S. Army Corps of Engineers for pipelines and utility projects. In May 2020, the court narrowed its ruling, vacating and enjoining the use of NWP 12 only as it relates to construction of new oil and gas pipelines. The U.S. Army Corps of Engineers appealed the decision to the U.S. Court of Appeals for the Ninth Circuit (“Ninth Circuit”). In July 2020, the U.S. Supreme Court stayed the lower court order except as it applies to the Keystone XL pipeline. In January 2021, the U.S. Army Corps of Engineers released the final version of a rule renewing twelve of its NWPs, including NWP 12. The new rule splits NWP 12 into three parts; NWP 12 will continue to be available to oil and gas pipelines, while new NWP 57 will be available for electric utility line and telecommunications activities, and a new NWP 58 will be available for utility line activities for water and other substances. The new rule also eliminates preconstruction notice requirements for NWP 12 for several conditions that used to require such notice, but also now requires new oil and gas pipeline projects that exceed 250 miles in length to give preconstruction notice and obtain approval before proceeding. As a result of the U.S. Army Corps of Engineer’s new NWP 12, the Ninth Circuit in August 2021 ruled that the appeal of the superseded NWP 12 was moot, and remanded the case back to the District Court. We cannot predict at this time whether and, if so, how the new rule will be implemented, because permits are issued by the local U.S. Army Corps of Engineers district offices. Moreover, in January 2021, the Biden administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. If new oil and gas pipeline projects are unable to utilize NWP 12 or identify an alternate means of CWA compliance, such projects could be significantly delayed, which could have an adverse impact on our operations.
The primary federal law related specifically to oil spill liability is the Oil Pollution Act of 1990 (the “OPA”), which amends and augments the oil spill provisions of the CWA and imposes certain duties and liabilities on certain “responsible parties” related to the prevention of oil spills and damages resulting from such spills in or threatening waters of the United States or adjoining shorelines. For example, operators of certain oil and natural gas facilities must develop, implement and maintain facility response plans, conduct annual spill training for certain employees and provide varying degrees of financial assurance. Owners or operators of a facility, vessel or pipeline that is a source of an oil discharge or that poses the substantial threat of discharge is one type of “responsible party” who is liable. The OPA applies joint and several liability, without regard to fault, to each liable party for oil removal costs and a variety of public and private damages. Although defenses exist, they are limited. As such, a violation of the OPA has the potential to adversely affect our operations.
Subsurface Injections
In the course of our operations, we produce water in addition to natural gas, crude oil and NGLs. Water that is not recycled may be disposed of in disposal wells, which inject the produced water into non-producing subsurface formations. Underground injection operations are regulated pursuant to the Underground Injection Control (the “UIC”) program established under the federal Safe Drinking Water Act (the “SDWA”) and analogous state laws. The UIC program requires permits from the EPA or an analogous state agency for the construction and operation of disposal wells, establishes minimum standards for disposal well operations, and restricts the types and quantities of fluids that may be disposed. A change in UIC disposal well regulations or the inability to obtain permits for new disposal wells in the future may affect our ability to dispose of produced water and ultimately increase the cost of our operations. For example, in response to recent seismic events near below-ground disposal wells used for the injection of natural gas- and oil-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such disposal
18
wells. In response to these concerns, regulators in some states have adopted, and other states are considering adopting, additional requirements related to seismic safety. The Railroad Commission of Texas (the “TRRC”) recently issued a notice to operators in the Midland area to reduce daily injection volumes following multiple earthquakes above a 3.5 magnitude over an 18-month period. The notice also required disposal well operators to provide injection data to TRRC staff to further analyze seismicity in the area. While we cannot predict the ultimate outcome of this notice, any action that temporarily or permanently restricts the availability of disposal capacity for produced water or other fluids may increase our costs or have other adverse impacts on our operations. These seismic events have also led to an increase in tort lawsuits filed against exploration and production companies, as well as the owners of underground injection wells. 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; however, these costs are commonly incurred by all oil, natural gas and NGL producers, and we do not believe that the costs associated with the disposal of produced water will affect our operations in any way that is of material difference from those of our competitors who are similarly situated.
Air Emissions
The federal Clean Air Act (the “CAA”) and comparable state laws restrict the emission of air pollutants from many sources, such as tank batteries, through air emissions standards, construction and operating permitting programs and the imposition of other compliance standards. These laws and regulations may require us to obtain pre-approval for the construction or modification of certain projects or facilities expected to produce or significantly increase air emissions, obtain and strictly comply with stringent air permit requirements or utilize specific equipment or technologies to control emissions of certain pollutants. The need to obtain permits has the potential to delay the development of our projects. Recently, there has been increased regulation with respect to air emissions from the oil and natural gas sector. For example, the EPA promulgated rules in 2012 under the CAA that subject oil and natural gas production, processing, transmission and storage operations to regulation under the New Source Performance Standards (“NSPS”), and a separate set of requirements to address certain hazardous air pollutants frequently associated with oil and natural gas production and processing activities pursuant to the National Emissions Standards for Hazardous Air Pollutants program.
In June 2016, the EPA published final rules establishing new air emission controls for methane emissions from certain new, modified or reconstructed equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The EPA’s final rules include NSPS at Subpart OOOOa to limit methane emissions from equipment and processes across the oil and natural gas source category. The rules also extend limitations on volatile organic compound (“VOC”) emissions to sources that were unregulated under the previous NSPS at Subpart OOOO. Affected methane and VOC sources include hydraulically fractured (or re-fractured) oil and natural gas well completions, fugitive emissions from well sites and compressors, and pneumatic pumps. In September 2018, the EPA proposed amendments to the 2016 rules that would reduce the 2016 rules’ fugitive emissions monitoring requirements and expand exceptions to controlling methane emissions from pneumatic pumps, among other changes. Various industry and environmental groups have separately challenged both the original 2016 methane requirements and EPA’s attempt to delay the implementation of the rule. Further, in August 2019, the EPA proposed two options for rescinding the Subpart OOOOa standards. In September 2020, the EPA finalized amendments to the 2016 standards that removed the transmission and storage segment from the oil and natural gas source category and rescinded the methane-specific requirements for production and processing facilities. However, as discussed above, in January 2021, the administration issued an executive order directing all federal agencies to review and take action to address any federal regulations, orders, guidance documents, policies, and similar agency actions promulgated during the prior administration that may be inconsistent with the current administration’s policies. The executive order specifically called on the EPA to consider a proposed rule suspending, revising or rescinding the September 2020 deregulatory amendments by September 2021. In response, the U.S. Congress has approved, and President Biden has signed into law, a resolution under the Congressional Review Act to repeal the September 2020 revisions to the methane standards, effectively reinstating the prior standards. In November 2021, as required by President Biden’s executive order, the EPA proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, including the exploration and production, transmission, processing, and storage segments. The EPA is currently seeking public comments on its proposal, which the EPA hopes to finalize by the end of 2022. Once finalized, the regulations are likely to be subject to legal challenge and will also need to be incorporated into the states’ implementation plans, which will need to be approved by the EPA in individual rulemakings that could also be subject to legal challenge. As a result, future implementation of the standards is uncertain at this time.
The Bureau of Land Management (the “BLM”) also finalized rules (the “BLM methane rule”) in November 2016 that seek to limit methane emissions from exploration and production activities on federal lands by imposing limitations on venting and flaring of natural gas, as well as requirements for the implementation of leak detection and repair programs for certain processes and equipment. After attempts by the Trump administration to delay implementation of the BLM methane rule, and legal challenges both to the BLM methane rule and the delays, the BLM issued a final rule in September 2018 rescinding many of the provisions of the 2016 BLM methane rule, including the requirement to implement leak detection and repair programs, and
19
imposing certain new requirements in a manner the BLM considered would reduce unnecessary compliance obligations on the industry. In July 2020 a federal district court in California vacated the 2018 rescission rule. BLM filed a notice of appeal to the U.S. Court of Appeals for the Ninth Circuit; however, the federal district court in California entered a final judgment vacating the September 2018 rescission rule in October 2020.
The EPA also finalized separate rules under the CAA in June 2016 regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and natural gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In addition, in October 2015, the EPA issued a final rule under the CAA lowering the National Ambient Air Quality Standards for ground-level ozone from the current standard of 75 parts per billion (“ppb”) for the current 8-hour primary and secondary ozone standards to 70 ppb for both standards. The final rule became effective on December 28, 2015. The EPA issued its anticipated area designations in November and December 2017. In December 2020, the EPA announced its intention to leave the ozone NAAQS unchanged at 70 ppb rather than lower them further. However, as discussed above, that action could be subject to reversal following the administration’s January 2021 executive order. States are expected to implement more stringent permitting and pollution control requirements as a result of this new final rule, which could apply to our operations.
Compliance with one or more of these and other air pollution control and permitting requirements and rules has the potential to delay the development of natural gas, oil and NGL projects and increase our costs of development and production, which costs could be significant.
Regulation of GHG Emissions
In response to findings that emissions of carbon dioxide, methane and other GHGs endanger public health and the environment, the EPA has adopted regulations under existing provisions of the CAA that, among other things, establish Prevention of Significant Deterioration (“PSD”) preconstruction and Title V operating permit reviews for certain large stationary sources that are already potential major sources of certain principal, or criteria, pollutant emissions. Facilities required to obtain PSD permits for their GHG emissions will also be required to meet “best available control technology” standards that will typically be established by state agencies. In addition, the EPA has adopted rules requiring the monitoring and annual reporting of GHG emissions from large GHG emission sources in the United States, including certain onshore and offshore natural gas, oil and NGL production sources, which include certain of our operations. As discussed above, federal regulatory action regarding GHG emissions from the oil and gas sector has focused on methane emissions; however, federal implementation of the finalized 2016 methane rule is uncertain at this time (as also discussed above).
While Congress has, from time to time, considered legislation to reduce emissions of GHGs, no significant legislation has been adopted at the federal level. In the absence of such federal climate legislation, a number of state and regional cap-and-trade programs have emerged that typically require major sources of GHG emissions to acquire and surrender emission allowances in return for emitting those GHGs. In addition, the United States is one of almost 200 nations that, in December 2015, agreed to the Paris Agreement, an international climate change agreement in Paris, France that calls for countries to set their own GHG emissions targets and be transparent about the measures each country will take to achieve its GHG emissions targets. The Paris Agreement entered into force on November 4, 2016 upon achieving its threshold for ratification by signatory countries. A long-term goal of the Paris Agreement is to limit global warming to below two degrees Celsius by 2100 from temperatures in the pre-industrial era. However, the Paris Agreement does not impose any binding obligations on its participants. In November 2019, the Trump administration initiated the formal process for withdrawing from the Paris Agreement, which resulted in an effective exit date of November 2020. However, President Biden has recommitted the United States to the Paris Agreement and, in April 2021, announced a goal of reducing the United States’ emissions by 50-52% below 2005 levels by 2030. In November 2021, the international community gathered again in Glasgow at the 26th Conference to the Parties on the UN Framework Convention on Climate Change (“COP26”), during which multiple announcements were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-carbon dioxide GHGs. Relatedly, the United States and European Union jointly announced the launch of the “Global Methane Pledge,” which aims to cut global methane pollution at least 30% by 2030 relative to 2020 levels, including “all feasible reductions” in the energy sector.
The executive order also established an Interagency Working Group on the Social Cost of Greenhouse Gases (“Working Group”), which is called on to, among other things, develop methodologies for calculating the “social cost of carbon,” “social cost of nitrous oxide,” and “social cost of methane.” The Working Group published interim values for three specific metrics (the Social cost of Carbon, Social Cost of Nitrous Oxide, and Social Cost of Methane) in February 2021, based on Obama-era estimates, and is now working to revise those values. Final recommendations from the Working Group are due no later than January 2022. A separate executive order targeting climate change, also issued by the current administration in January 2021, directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters, or take other appropriate actions to
20
account for corresponding climate costs. The climate change executive order also directed the federal government to identify “fossil fuel subsidies” to take steps to ensure that, to the extent consistent with applicable law, federal funding is not directly subsidizing fossil fuels. Legal challenges to the executive orders have been filed.
Although it is not possible at this time to predict how new laws or regulations that may be adopted or issued to address GHG emissions would impact our business, any such future laws, regulations or legal requirements imposing reporting or permitting obligations on, or limiting emissions of GHGs from, our equipment and operations could require us to incur costs to reduce emissions of GHGs associated with our operations, as well as delay or restrict our ability to permit GHG emissions from new or modified sources. In addition, substantial limitations on GHG emissions could adversely affect demand for the natural gas, oil and NGLs we produce and lower the value of our reserves. Finally, it should be noted that increasing concentrations of GHGs in the Earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, floods, droughts and other extreme climatic events; if any such effects were to occur, they could have an adverse effect on our exploration and production operations.
Hydraulic Fracturing Activities
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil, natural gas and NGLs from dense subsurface rock formations. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions. However, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA published final CAA regulations in 2012 and, more recently, in June 2016, establishing performance standards, including standards for the capture of air emissions released during oil and natural gas hydraulic fracturing, leak detection, and permitting (which are subject to revision, as discussed above); published in June 2016 an effluent limitation guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants; and issued in 2014 a prepublication version of its Advance Notice of Proposed Rulemaking regarding Toxic Substances Control Act (“TSCA”) reporting of the chemical substances and mixtures used in hydraulic fracturing. Also, in March 2015, the BLM adopted rules establishing stringent standards relating to hydraulic fracturing on federal and American Indian lands. In June 2016, a federal district court judge in Wyoming struck down this final rule, finding that the BLM lacked authority to promulgate the rule. That ruling was appealed, but in September 2017 the U.S. Court of Appeals for the Tenth Circuit dismissed the appeal and remanded with directions to vacate the lower court’s opinion, leaving the final rule in place. However, following the issuance of an executive order by President Trump to review rules related to the energy industry, the BLM initiated a rulemaking to rescind the final rule in December 2017. Shortly after the final rulemaking was issued, the state of California and several environmental groups filed lawsuits against the BLM, the Secretary of the Interior, and the Assistant Secretary for Land and Minerals Management, seeking an injunction and a declaration that the repeal violated numerous federal statutes. After the suits were filed, multiple industry groups and the state of Wyoming sought to intervene and transfer the case to federal court in Wyoming, which decided the initial legal challenge to the Obama administration’s fracking regulations. A hearing was held in January 2020 to consider a motion for summary judgment in the case, and in March 2020, the court granted BLM’s motion for summary judgment, upholding the agency’s decision to rescind the hydraulic fracturing regulations finalized in the 2015 rule. Also, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under certain limited circumstances.”
From time to time, legislation has been introduced, but not enacted, in Congress to provide for federal regulation of hydraulic fracturing and to require disclosure of the chemicals used in the fracturing process. Meanwhile, the regulation of hydraulic fracturing has continued at the state level. For example, Wyoming has promulgated rules related to the public disclosure of substances used in hydraulic fluid, testing requirements for water wells near drilling sites and leak detection and repair requirements for fugitive emissions from oil and gas production facilities.
In the event that a new, federal level of legal restrictions relating to the hydraulic fracturing process is adopted in areas where we operate, we may incur additional costs to comply with such federal requirements that may be significant in nature, and also could become subject to additional permitting requirements and experience added delays or curtailment in the pursuit of exploration, development, or production activities.
21
Activities on Federal Lands and State Lands
Oil and natural gas exploration, development and production activities on federal lands, including American Indian lands and lands administered by the BLM, are frequently subject to permitting delays. Operations on these lands are also subject to the National Environmental Policy Act (“NEPA”). NEPA requires federal agencies, including the BLM, to evaluate major actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. In January 2020, the White House Council on Environmental Quality (“CEQ”) proposed changes to NEPA regulations designed to overhaul the system and speed up federal agencies’ approval of projects. Among other things, the rule proposes to narrow the definition of “effects” to exclude the terms “direct,” “indirect,” and “cumulative” and redefine the term to be “reasonably foreseeable” and having “a reasonably close causal relationship to the proposed action or alternatives.” In July 2020, CEQ issued a final rule implementing the January 2020 proposal. However, several states and environmental groups have filed challenges to this rulemaking, and CEQ’s amendments are subject to reconsideration and may be subject to reversal or change under the Biden administration. Additionally, in October 2021, the CEQ issued a notice of proposed rulemaking to reintroduce certain requirements removed or reduced by the July 2020 amendments, and the Infrastructure and Investment Jobs Act, Pub.L. 117-58, signed into law in November 2021, codified some of the July 2020 amendments in statutory text. These amendments must be implemented into each agency’s implementing regulations, and each of those individual rulemakings could be subject to legal challenge. The impact of changes to the NEPA regulations and statutory text therefore remains uncertain and could have an effect on our operations and our ability to obtain governmental permits. We currently have exploration, development and production activities on federal lands. Our proposed exploration, development and production activities are expected to include leasing of federal mineral interests, which will require the acquisition of governmental permits or authorizations that are subject to the requirements of NEPA. This process has the potential to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects. Authorizations under NEPA are also subject to protest, appeal or litigation, any or all of which may delay or halt projects. Moreover, depending on the mitigation strategies recommended in the Environmental Assessments or Environmental Impact Statements, we could incur added costs, which may be substantial. However, any such adverse regulatory developments are expected to have no more than a minimal impact on our results, given our limited exposure of leases on federal lands (less than five percent of our total interests).
In addition, the New Mexico state legislature recently considered House Bill 206, which, if passed, would have enacted an Environmental Review Act comparable to NEPA. Specifically, the Environmental Review Act would require state governmental agencies at all levels to consider the qualitative, technical and economic factors relating to a project that may impact public health, ecosystems and the environment, the long-term as well as short-term benefits and costs of the proposed project, the cumulative impacts of the proposed project, and reasonable alternatives to proposed actions affecting the environment, communities or public health. If reconsidered and enacted in the future, the process contemplated by the Environmental Review Act has the potential, like NEPA, to delay or limit, or increase the cost of, the development of natural gas, oil and NGL projects in New Mexico, which costs could be substantial.
ESA and Migratory Birds
The federal Endangered Species Act (“ESA”) and comparable state laws were established to protect endangered and threatened species. Pursuant to the ESA, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. We may conduct operations on oil and natural gas leases in areas where certain species that are listed as threatened or endangered are known to exist and where other species that potentially could be listed as threatened or endangered under the ESA may exist. Moreover, as a result of a 2011 settlement agreement, the U.S. Fish and Wildlife Service (the “FWS”) was required to make a determination on listing of numerous species as endangered or threatened under the ESA by no later than completion of the agency’s 2017 fiscal year. The FWS did not meet that deadline. In August 2020, the FWS and the National Marine Fisheries Service issued three rules amending the implementation of the ESA regulations, among other things revising the process for listing species and designating critical habitat. A coalition of states and environmental groups has challenged the three rules and the litigation remains pending. However, the Biden administration published two rules in October 2021 that reversed changes made by the Trump administration, namely to the definition of “habitat” and to a policy that made it easier to exclude territory from critical habitat under the ESA. It is possible those developments could, in the future, affect our operations if the areas in which we operate are designated as critical or suitable habitat.
In addition, the federal government recently has issued indictments under the Migratory Bird Treaty Act (“MBTA”) to several oil and natural gas companies after migratory birds were found dead near reserve pits associated with drilling activities. The Department of the Interior issued an opinion in December 2017 that would narrow certain protections afforded to migratory birds pursuant to the MBTA. In response to this opinion, two separate lawsuits were filed in May 2018 in the U.S. District Court for the Southern District of New York challenging the Department of the Interior’s interpretation of the MBTA. In September 2018, eight states filed a similar suit in the U.S. District Court for the Southern District of New York. In February 2020, the FWS
22
published a rule seeking to codify the December 2017 legal opinion. In August 2020, the District Court struck down the December 2017 opinion, and the Department of the Interior responded by issuing a new rule in January 2021 that reduced the activities that could incur liability under the MBTA. The Biden administration has since revoked the January 2021 rule; published an Advanced Notice of Proposed Rulemaking announcing an intent to solicit comments to help develop proposed regulations establishing a permitting system to authorize, under certain circumstances, the incidental take of migratory birds; and issued a Director’s Order “establishing criteria for the types of conduct that will be a priority for enforcement activities with respect to incidental take of migratory birds.” The identification or designation of previously unprotected species as threatened or endangered in areas where underlying property operations are conducted could cause us to incur increased costs arising from species protection measures, time delays or limitations on our exploration and production activities, which could have an adverse impact on our ability to develop and produce reserves. If we were to have a portion of our leases designated as critical or suitable habitat, it could adversely impact the value of our leases.
OSHA
We are subject to the requirements of the Occupational Safety and Health Act (“OSHA”) and comparable state statutes whose purpose is to protect the health and safety of workers. In addition, OSHA’s hazard communication standard, the Emergency Planning and Community Right-to-Know Act, comparable state statutes and any implementing regulations require that we organize and/or disclose information about hazardous materials used or produced in our operations and that this information be provided to employees, state and local governmental authorities and citizens.
Related Permits and Authorizations
Many environmental laws require us to obtain permits or other authorizations from state and/or federal agencies before initiating certain drilling, construction, production, operation or other activities and to maintain these permits and compliance with their requirements for ongoing operations. These permits are generally subject to protest, appeal or litigation, which can in certain cases delay or halt projects and cease production or operation of wells, pipelines and other operations.
Related Insurance
We maintain insurance against some risks associated with above or underground contamination that may occur as a result of our development activities. However, this insurance is limited to activities at the well site and there can be no assurance that this insurance will continue to be commercially available or that this insurance will be available at premium levels that justify its purchase by us. The occurrence of a significant event that is not fully insured or indemnified against could have a materially adverse effect on our financial condition and operations.
Human Capital Resources
We aim to attract and retain top-tier talent in the oil and gas sector and empower our employees to be innovators in our industry. As of December 31, 2021, we had 147 full-time employees. In addition, we hire independent contractors on an as needed basis but have no collective bargaining or employment agreements with our employees.
We believe that our employees give us a sustainable competitive advantage, and we understand the need to attract, retain and train the best team possible. We provide fair and competitive wages to assist in retention of our top talent, and our compensation programs are integrated with our overall business strategies to incentivize performance and maximize shareholder returns. In addition, we conduct a gender and ethnic pay analysis at least annually to ensure that we are adequately and fairly compensating all employees based on their experience and performance. We offer a variety of programs that are designed to retain our employees and also provide opportunities to grow their professional careers while continuing to deliver value to the company. Additionally, we maintain a comprehensive suite of benefits that provide our employees with various options including retirement, health and wellness, and life and disability plans.
We are committed to a diverse workforce because we believe employees with different backgrounds, experiences, interests and skillsets drive superior results. In terms of gender and racial distribution, approximately 37% of our employees identify as female and approximately 21% of our employees identify as non-white. We plan to continue to recruit and develop a diverse workforce to ensure that we remain an employer of choice delivering top-tier results.
We strive to promote a safe and healthy working environment with a focus on protecting our employees, contractors, the public and the environment in the communities in which we conduct our business. We provide frequent trainings and monthly safety meetings for all field employees and have excelled in health, safety and environmental performance maintaining zero employee recordable incidents due to illnesses or injuries at the workplace.
Offices
Our principal executive offices are located at 1001 17th Street, Suite 1800, Denver, Colorado 80202, and our telephone number is (720) 499-1400. We also have office space in Midland, Texas; Pecos, Texas; and Eunice, New Mexico.
23
Available Information
Our internet website address is www.cdevinc.com. We routinely post important information for investors on our website. Within our website’s investor relations section, we make available free of charge our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and amendments to those reports filed with or furnished to the SEC under applicable securities laws. These materials are made available as soon as reasonably practical after we electronically file such materials with or furnish such materials to the SEC. Information on our website is not incorporated by reference into this Annual Report and should not be considered part of this document.
The SEC maintains a website that contains reports, proxy and information statements and other information regarding issuers that file electronically with the SEC at www.sec.gov.
24
ITEM 1A. RISK FACTORS
You should carefully consider the following risk factors together with all of the other information included in this Annual Report and our other reports filed with the SEC before investing in our securities. The occurrence of one or more of these risks could materially and adversely affect our business, our financial condition, and the results of our operations, which in turn could negatively impact the value of our securities.
Risks Related to Commodity Prices
The COVID-19 pandemic and related governmental actions have and may continue to lead to an imbalance in expected supply and demand of oil and natural gas, which could negatively impact commodity prices and therefore our business, financial condition and results of operations.
The COVID-19 pandemic and various governmental actions taken to mitigate the impact of COVID-19 resulted in an unprecedented decline in demand for oil, natural gas and NGLs during 2020.
In 2021, worldwide demand for oil, natural gas and NGLs increased from 2020 levels while the supply of these commodities increased, but have not returned to pre-pandemic levels, through commitments made by the OPEC and other oil producing countries and actions by U.S. producers to substantially reduce drilling and producing activities. While these factors led to higher commodity prices in 2021, commodity prices have remained volatile. The remaining uncertainty around COVID-19, including the transmissibility and severity of new variants, and actions by governments to combat the spread of the virus, continue to impact actual and expected demand for oil, natural gas and NGLs. To the extent the demand declines due to COVID-19 factors or producers fail to sustain production cuts or take other actions that are sufficient to balance oil, natural gas and NGLs supply with expected demand, the excess supply could lead to a reversion to commodity price declines. As the vast majority of our revenue and cash flow is generated from the sale of oil, natural gas and NGLs, lower commodity prices resulting from COVID-19 factors could materially and adversely affect our future business, financial condition and results of operations.
Commodity prices are volatile, and a sustained period of low commodity prices for oil, natural gas and NGLs could adversely affect our business, financial condition and results of operations.
The prices we receive for our oil, natural gas and NGLs heavily influence our revenue, cash flows, profitability, access to capital, future rate of growth and carrying value of our properties. Oil, natural gas and NGLs are commodities, and their prices may fluctuate widely in response to relatively minor changes in the actual and expected supply of and demand for oil, natural gas and NGLs and market uncertainty. In addition to the influence of the COVID-19 pandemic and related governmental actions, discussed above, oil, natural gas and NGL prices have historically been volatile and subject to fluctuations relating to a variety of additional factors that are beyond our control, including:
•worldwide and regional economic conditions impacting the global supply of and demand for oil, natural gas and NGLs;
•the price and quantity of foreign imports of oil, natural gas and NGLs;
•political and economic conditions in or affecting other producing regions or countries, including the Middle East, Russia, Eastern Europe, Africa and South America;
•actions of OPEC, its members and other state-controlled oil companies relating to oil price and production controls;
•actions of U.S. producers, and independent producers operating in other countries, relating to production levels;
•political, economic and other conditions that affect perceived demand for oil, natural gas and NGLs, including international trade disputes, sanctions and global health pandemics, epidemics and concerns;
•the level of global exploration, development, production, and inventories;
•actions of U.S. and other governments to strategically release oil, natural gas and NGLs from strategic reserves;
•the availability of refining and storage capacity;
•prevailing prices on local price indexes in the area in which we operate;
•the proximity, capacity, cost and availability of gathering and transportation facilities;
•the cost of exploring for, developing, producing and transporting reserves;
•weather conditions and other natural disasters;
•terrorist attacks targeting oil and natural gas related facilities and infrastructure;
•technological advances affecting fuel economy, energy supply and energy consumption;
•the effect of energy conservation measures, alternative fuel requirements and the price and availability of alternative fuels;
•laws, regulations and taxes in the U.S. and in foreign jurisdictions that impact the demand for oil, natural gas and NGLs;
25
•shareholder activism or activities by non-governmental organizations to restrict the exploration and production of oil and natural gas so as to minimize emissions of carbon dioxide and methane GHGs or otherwise;
•localized and global supply and demand fundamentals; and
•expectations about future commodity prices.
These factors and the volatility of the energy markets make it extremely difficult to predict future oil, natural gas and NGL price movements with any certainty. From 2017 through 2021, the WTI spot price for oil averaged $56.18 per Bbl, which is down substantially from the $75.50 average for the prior five-year period. The Henry Hub average spot price from 2017 through 2021 of $2.92 per MMBtu similarly declined from $3.19 per MMBtu, which was the average for the prior five-year period. The commodity prices displayed even more dramatic volatility in 2020, during which the WTI spot price for oil briefly fell to a low of negative $37.63 per barrel on April 20, 2020 and the Henry Hub spot price reached a low of $1.33 on September 21, 2020. During these periods, NGLs, which are made up of ethane, propane, isobutene, normal butane and natural gasoline, all of which have different uses and different pricing characteristics, have suffered significant recent price declines.
A sustained or extended decline in commodity prices may result in a shortfall in our expected revenues and cash flows and require us to reduce capital spending or borrow funds to cover any such shortfall. If we are unable to obtain needed capital or financing on satisfactory terms, our ability to develop future reserves could be adversely affected. Also, using lower prices in estimating proved reserves may result in a reduction in proved reserve volumes due to economic limits. In addition, sustained periods of low commodity prices for oil and natural gas and the resultant effect such prices may have on our drilling economics and our ability to raise capital may require us to re-evaluate and postpone, moderate or eliminate our planned drilling and completions operations, or suspend production from current wells, which could result in the reduction of our expected production and some of our proved undeveloped reserves and related standardized measure. If we moderate or curtail our drilling, completion or production operations, we may be unable to continue to hold leases that are scheduled to expire, which may further reduce our reserves. As a result, a sustained or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity and ability to finance planned capital expenditures.
If commodity prices decrease to a level such that our future undiscounted cash flows from our properties are less than their carrying value, we may be required to take write-downs of the carrying values of our properties.
Accounting guidance requires that we periodically review the carrying value of our properties for possible impairment. Based on prevailing commodity prices and specific market factors and circumstances at the time of prospective impairment reviews, and the continuing evaluation of development plans, production data, economics and other factors, we may be required to write-down the carrying value of our properties. A write-down constitutes a non-cash charge to earnings. In 2020, we recognized an impairment of $591.8 million because of the depressed oil and natural gas commodity prices at the time we conducted the impairment analysis in the first quarter. While commodity prices improved in 2021 resulting in no impairments directly relating to prevailing commodity prices, a sustained or extended decline in commodity prices in the future could result in additional impairments of our properties, which could have a material adverse effect on our results of operations for the periods in which such charges are taken.
Risks Related to Our Reserves, Leases and Drilling Locations
Reserve estimates depend on many assumptions that may turn out to be inaccurate. Any material inaccuracies in reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves.
The process of estimating oil and natural gas reserves is complex. In order to prepare reserve estimates, we must project production rates and timing of development expenditures. We must also analyze available geological, geophysical, seismic, production and engineering data. The extent, quality and reliability of this data can vary. The process also requires economic assumptions about matters such as commodity prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Any significant inaccuracies in our interpretations of this technical data or in making our assumptions could materially affect the estimated quantities and present value of our reserves.
Actual future production, commodity prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary from our estimates. For instance, initial production rates reported by us or other operators may not be indicative of future or long-term production rates, our recovery efficiencies may be worse than expected, and production declines may be greater than our estimates and may be more rapid and irregular when compared to initial production rates. In addition, we may adjust reserve estimates to reflect additional production history, results of development activities, current commodity prices and other existing factors. Any significant variance could materially affect the estimated quantities and present value of our reserves.
You should not assume that the present value of future net revenues from our reserves is the current market value of our estimated reserves. We generally base the estimated discounted future net cash flows from reserves on prices and costs on the date of the estimate. Actual future prices and costs may differ materially from those used in the present value estimate. Our estimated proved reserves as of December 31, 2021, and related standardized measure were calculated under rules of the SEC using twelve-
26
month trailing average benchmark prices of $63.04 per barrel of oil (WTI Posted) and $3.60 per MMBtu (Henry Hub spot), which may be substantially higher or lower than the available spot prices in 2022. For example, if the crude oil and natural gas prices used in our year-end reserve estimates were to increase or decrease by 10%, our proved reserve quantities at December 31, 2021 would increase by 1.1 MMBoe (0.3%) or decrease by 2.1 MMBoe (0.7%), respectively, and the pre-tax PV10% of our proved reserves would increase by $626.0 million (16%) or decrease by $630.5 million (16%), respectively.
Our use of seismic data is subject to interpretation and may not accurately identify the presence of oil and natural gas, which could adversely affect the results of our drilling operations.
Even when properly used and interpreted, seismic data and visualization techniques are only tools used to assist geoscientists in identifying subsurface structures and hydrocarbon indicators and do not enable the interpreter to know whether hydrocarbons are, in fact, present in those structures. As a result, our drilling activities may not be successful or economical. In addition, the use of advanced technologies, such as 3-D seismic data, requires greater pre-drilling expenditures than traditional drilling strategies, and we could incur losses as a result of such expenditures.
Unless we replace our reserves with new reserves and develop those reserves, our reserves and production will decline, which would adversely affect our future cash flows and results of operations.
Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Unless we conduct successful ongoing exploration and development activities or continually acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Our future reserves and production, and therefore our future 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, particularly because competition in the oil and natural gas industry is intense, and many of our competitors possess and employ financial, technical and personnel resources substantially greater than ours. 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 would be materially and adversely affected.
The development of our estimated PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our estimated PUDs may not be ultimately developed or produced.
As of December 31, 2021, 47% of our total estimated proved reserves were classified as proved undeveloped. Development of these proved undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the value of our estimated PUDs and future net revenues estimated for such reserves and may result in some projects becoming uneconomic. In addition, delays in the development of reserves could cause us to have to reclassify our PUDs as unproved reserves. Further, we may be required to write-down our PUDs if we do not drill those wells within five years after their respective dates of booking.
Certain of our undeveloped leasehold acreage is subject to leases that will expire over the next several years unless production is established on units containing the acreage, the primary term is extended through continuous drilling provisions or the leases are renewed.
As of December 31, 2021, over 96% of our total net acreage was held by production. The leases for our net acreage not held by production will expire at the end of their primary term unless production is established in paying quantities under the units containing these leases, the leases are held beyond their primary terms under continuous drilling provisions or the leases are renewed. Some of our leases also expire as to certain depths if continuous drilling obligations are not met. If our leases expire in whole or in part and we are unable to renew the leases, we will lose the right to develop the related properties. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, gathering system and pipeline transportation constraints, access to and availability of water sourcing and distribution systems, regulatory approvals and other factors.
In the future, we may shut-in some or all of our production depending on market conditions, storage or transportation constraints and contractual obligations, and any prolonged shut-in of our wells could result in the expiration, in whole or in part, of the related leases, which could adversely affect our reserves, business, financial condition and results of operations.
Our identified drilling locations are scheduled out over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
We have specifically identified and scheduled certain drilling locations as an estimation of our future multi-year drilling activities on our existing acreage. These drilling locations represent a significant part of our business strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including commodity prices, the availability and cost of capital, drilling and production costs, availability of drilling services and equipment, drilling results, lease expirations, availability of
27
gathering or transportation facilities, access to and availability of water sourcing and distribution systems, regulatory approvals, including permitting, and other factors. Because of these uncertain factors, we do not know if the numerous identified drilling locations will ever be drilled or if we will be able to produce natural gas or oil from these or any other drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the drilling locations are obtained, the leases for such acreage will expire. As such, our actual drilling activities may materially differ from those presently identified.
Properties that we decide to drill may not yield oil or natural gas in commercially viable quantities.
Properties that we decide to drill that do not yield oil or natural gas in commercially viable quantities will adversely affect our results of operations and financial condition. There is no way to predict in advance of drilling and testing whether any particular prospect will yield oil or natural gas in sufficient quantities to recover drilling or completion costs or be economically viable. The use of micro-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 oil or natural gas will be present or, if present, whether oil or natural gas will be present in commercial quantities. We cannot assure you that the analogies we draw from available data from other wells, more fully explored prospects or producing fields will be applicable to our drilling prospects.
Risks Related to Our Operations
Our development and acquisition projects require substantial capital expenditures. We may be unable to obtain required capital or financing on satisfactory terms, which could lead to a decline in our ability to access or grow production and reserves.
The oil and natural gas industry is capital-intensive. We make and expect to continue to make substantial capital expenditures related to development and acquisition projects. Historically, we have funded our capital expenditures with cash flows from operations, borrowings under CRP’s revolving credit facility, proceeds from offering debt and equity securities and divestitures of non-core assets, and we intend to finance our future capital expenditures in a similar fashion. When we finance our capital expenditures through indebtedness a portion of our cash flows from operations must be used to pay interest and principal on the indebtedness, which reduces our ability to use cash flows from operations to fund working capital, capital expenditures and acquisitions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, oil, natural gas and NGL prices; actual drilling results; the availability of drilling rigs and other services and equipment; and regulatory, technological and competitive developments.
Our cash flow from operations and access to capital are subject to a number of variables, including:
•the prices at which our production is sold;
•our proved reserves;
•the level of hydrocarbons we are able to produce from existing wells;
•our ability to acquire, locate and produce new reserves;
•the levels of our operating expenses; and
•our ability to borrow under CRP’s revolving credit facility and to access the capital markets.
If our revenues or the borrowing base under CRP’s revolving credit facility decrease as a result of lower oil, natural gas and NGL prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be able to obtain debt or equity financing on terms acceptable to us, if at all. If cash flow generated by our operations or available borrowings under CRP’s revolving credit facility are not sufficient to meet our capital requirements, the failure to obtain additional financing could result in a curtailment of our operations relating to development of our properties. This, in turn, could lead to a decline in our reserves and production, and could materially and adversely affect our business, financial condition and results of operations.
Drilling for and producing oil and natural gas are high risk activities with many uncertainties that could adversely affect our business, financial condition or results of operations. Additionally, 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 will depend on the success of our development, acquisition and production activities, which are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. In addition to the risks we face in drilling for and producing oil and natural gas, some factors that may directly or indirectly negatively impact our scheduled operations:
•lack of available gathering or transportation facilities or delays in the constructing such facilities;
•abnormal pressure or irregularities in geological formations;
•shortages of or delays in obtaining equipment, qualified personnel, materials or resources;
28
•equipment failures, accidents or other unexpected operational events;
•delays imposed by or resulting from compliance with laws and regulations, including limitations resulting from wastewater disposal, emission of GHGs and limitations on hydraulic fracturing;
•environmental hazards, such as oil and natural gas leaks, oil spills, pipeline and tank ruptures and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
•natural disasters;
•personal injuries and death;
•terrorist attacks targeting oil and natural gas related facilities and infrastructure;
•limited availability of financing at acceptable terms;
•title problems;
•adverse weather conditions; and
•limitations in the market for oil and natural gas.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events, including those operating risks listed above, could materially and adversely affect our business, financial condition or results of operations. We may elect not to obtain insurance for any or all of these risks if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable. The occurrence of an event that is not fully covered by insurance could have a material adverse effect on our business, financial condition and results of operations.
Many of our properties are in areas that may have been partially depleted or drained by offset wells and certain of our wells may be adversely affected by actions other operators may take when drilling, completing, or operating wells that they own.
Many of our properties are in areas that may have already been partially depleted or drained by earlier offset drilling. The owners of leasehold interests adjoining any of our properties could take actions, such as drilling and completing additional wells, which could adversely affect our operations. When a new well is completed and produced, the pressure differential in the vicinity of the well causes the migration of reservoir fluids toward the new wellbore (and potentially away from existing wellbores). As a result, the drilling and production of these potential locations could cause a depletion of our proved reserves and may inhibit our ability to further develop our proved reserves. In addition, completion operations and other activities conducted on adjacent or nearby wells could cause production from our wells to be shut in for indefinite periods of time, could result in increased lease operating expenses and could adversely affect the production and reserves from our wells after they re-commence production. We have no control over the operations or activities of offsetting operators.
Part of our strategy involves using some of the latest available horizontal drilling and completion techniques, which involve risks and uncertainties in their application.
Our operations involve utilizing some of the latest drilling and completion techniques as developed by us and our service providers. Risks that we face while drilling horizontal wells include:
•landing a wellbore in the desired drilling zone,
•staying in the desired drilling zone while drilling horizontally through the formation and
•spacing the wells appropriately to maximize production rates and recoverable reserves.
Risks that we face while completing wells include:
•the ability to fracture stimulate the planned number of stages,
•the ability to run tools the entire length of the wellbore during completion operations and
•the ability to prevent unintentional communication with other wells.
If our drilling results are less than anticipated, the return on our investment for a particular project may not be as attractive as anticipated, and we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Our operations are substantially dependent on the availability of water. Restrictions on our ability to obtain water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of deep shale oil and natural gas production during both the drilling and hydraulic fracturing processes. Drought conditions have persisted in Texas in past years. These drought conditions have led some local water districts to restrict the use of water subject to their jurisdiction for hydraulic fracturing to protect local water supplies. Where practicable, we strive to use recycled water for our hydraulic fracturing operations. If we are unable to obtain water from water suppliers or
29
our recycling operations, it may need to be obtained from non-local sources and transported to drilling sites, resulting in increased costs, or we may be unable to economically drill for or produce oil and natural gas, each of which could have an adverse effect on our financial condition, results of operations and cash flows.
Our ability to produce crude oil, natural gas and NGLs economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to recycle or dispose of the produced water we produce in an economical and environmentally safe manner.
Our operations could be impaired if we are unable to recycle or dispose of the water we produce in an economical and environmentally safe manner. Where practicable, we strive to recycle the produced water for our future oil and gas operations. Produced water that is not recycled generally gets disposed of in disposal wells that are operated by us or third-party contractors. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection of produced water resulting from oil and gas activities, which has led to increased public and governmental scrutiny of injection safety. For instance, in response to concerns regarding induced seismicity, regulators in Texas have adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and gas. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity.
Another consequence of water disposal activities and seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on our use of injection wells or commercial disposal wells to dispose of produced water. Increased regulation and attention given to water disposal and induced seismicity could also lead to greater opposition, including litigation, to limit or prohibit oil and gas activities utilizing injection wells for produced water disposal. Any one or more of these developments may result in limitations on disposal well volumes, disposal rates and pressures or locations, require us or our vendors to shut down or curtail the injection into disposal wells, or cause delays, interruptions or termination of our operations, which events could have a material adverse effect on our business, financial condition and results of operations.
Our producing properties are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, making us vulnerable to risks associated with operating in a single geographic area.
Our producing properties are geographically concentrated in the Delaware Basin, a sub-basin of the Permian Basin, primarily in West Texas and New Mexico. At December 31, 2021, all of our total estimated proved reserves were attributable to properties located in this area. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, market limitations, availability of equipment and personnel, water shortages, regional power outages or other drought or extreme weather related conditions or interruption of the processing or transportation of oil, natural gas or NGLs. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
The marketability of our production is dependent upon transportation and other facilities, most of which we do not control. If these facilities are unavailable, or if we are unable to access these facilities on commercially reasonable terms, our operations could be interrupted and our revenues reduced.
The marketability of our oil, natural gas and NGLs production depends in part upon the availability, proximity and capacity of transportation facilities owned by third parties. Our oil, natural gas and NGLs production is generally transported from the wellhead by gathering systems that are either owned by us or third-party midstream companies. In general, we do not control the transportation of our production and our access to transportation facilities may be limited or denied. In some instances, we have contractual guarantees relating to the transportation of our production through firm transportation arrangements, but third-party systems may be temporarily unavailable due to market conditions, mechanical failures, accidents or other reasons. Insufficient production from our wells to support the construction of pipeline facilities by our purchasers or third-party midstream companies or a significant disruption in the availability of our or third-party transportation facilities or other production facilities could adversely impact our ability to deliver to market or produce our oil, natural gas and NGLs and thereby cause a significant interruption in our operations. If, in the future, we are unable, for any sustained period, to implement acceptable delivery or transportation arrangements, we may be required to shut in or curtail production or flare our natural gas. If we were required to shut-in wells, we might also be obligated to pay certain demand charges for gathering and processing services and firm transportation charges for pipeline capacity we have reserved. Any such shut-in or curtailment, or an inability to obtain favorable
30
terms for delivery of the oil, natural gas and NGLs produced from our fields, would materially and adversely affect our financial condition and results of operations.
We have entered into multi-year agreements with some of our suppliers, service providers and the purchasers of our oil and natural gas, which contain minimum volume commitments. Any failure by us to satisfy the minimum volume commitments could lead to contractual penalties that could adversely affect our results of operations and financial position.
We have entered into certain multi-year supply and service agreements associated with energy purchase agreements. We also have various multi-year agreements that relate to the sale, transportation or gathering of our oil and natural gas and may in the future enter into multi-year agreements for contracts for drilling rigs or other services. Some of these agreements contain minimum volume commitments that we must satisfy or contractual penalties in the form of volume deficiencies or other remedies may apply. As of December 31, 2021, our aggregate long-term contractual obligation under these agreements was $28.9 million, which represents the gross minimum obligation but does not include amounts that may be due under certain contracts that contain variable pricing or volumetric components as the future obligations cannot be determined. Further information about these agreements can be found at Note 13—Commitments and Contingencies, Item 8. Financial Statements and Supplementary Data in this Annual Report. Any failure by us to satisfy the minimum volume commitments in these agreements could adversely affect our results of operations and financial position.
The unavailability or high cost of additional drilling rigs, equipment, supplies, personnel and oilfield services could adversely affect our ability to execute our development plans within our budget and on a timely basis.
The demand for drilling rigs, pipe and other equipment and supplies, as well as for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry, can fluctuate significantly, often in correlation with commodity prices, causing periodic shortages. In addition, to the extent our suppliers source their products or raw materials from foreign markets, the cost of such equipment could be impacted if the United States imposes tariffs on imported goods from countries where these goods are produced. We cannot predict whether these conditions will exist in the future and, if so, what their timing and duration will be. Such shortages or cost increases could delay or cause us to incur significant expenditures that are not provided for in our capital budget, which could have a material adverse effect on our business, financial condition or results of operations.
We could experience periods of higher costs if commodity prices rise. These increases could reduce our profitability, cash flow and ability to complete development activities as planned.
Historically, our capital and operating costs have risen during periods of increasing oil, natural gas and NGL prices. These cost increases result from a variety of factors beyond our control, such as increases in the cost of electricity, steel and other raw materials that we and our vendors rely upon; increased demand for labor, services and materials as drilling activity increases; and increased taxes. Such costs may rise faster than increases in our revenue as commodity prices rise, thereby negatively impacting our profitability, cash flows and ability to complete development activities as scheduled and on budget. This impact may be magnified to the extent that our ability to participate in the commodity price increases is limited by our derivative activities.
We depend upon a small number of significant purchasers for the sale of most of our oil, natural gas and NGL production.
We normally sell production to a relatively small number of customers, as is customary in our business. See Note 1—Basis of Presentation and Summary of Significant Accounting Policies, Item 8. Financial Statements and Supplementary Data in this Annual Report for significant purchasers that accounted for more than 10% of our revenues for the years ended December 31, 2021, 2020 and 2019. The loss of any of our major purchasers could materially and adversely affect our revenues in the near-term.
We may incur losses as a result of title defects in the properties in which we invest.
The existence of a material title deficiency can render a lease worthless and can adversely affect our results of operations and financial condition. While we typically obtain title opinions prior to commencing drilling operations on a lease or in a unit, the failure of title may not be discovered until after a well is drilled, in which case we may lose the lease and the right to produce all or a portion of the minerals under the property.
Multi-well pad drilling may result in volatility in our operating results.
We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production from a given pad, which may cause volatility in our operating results. In addition, problems affecting one pad could adversely affect production from all wells on such pad. As a result, multi-well pad drilling can cause delays in the scheduled commencement of production or interruptions in ongoing production.
31
We may be unable to make attractive acquisitions or successfully integrate acquired businesses, and any inability to do so may disrupt our business and hinder our ability to grow.
In the future we may make acquisitions of assets or businesses that complement or expand our current business. The successful acquisition of producing properties requires an assessment of several factors, including:
•recoverable reserves;
•future commodity prices and their applicable differentials;
•operating costs; and
•potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. 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. Inspections may not always be performed on every well, and environmental problems, such as groundwater contamination, are not necessarily observable even when an inspection is undertaken. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis.
The success of any completed acquisition will depend on our ability to integrate effectively the acquired business into our existing operations. The process of integrating acquired businesses may involve unforeseen difficulties and may require a disproportionate amount of our managerial and financial resources. In addition, possible future acquisitions may be larger and purchase prices higher than those paid for earlier acquisitions. No assurance can be given that we will be able to identify additional suitable acquisition opportunities, negotiate acceptable terms, obtain financing for acquisitions on acceptable terms or successfully acquire identified targets. Our failure to achieve consolidation savings, to integrate the acquired businesses and assets into our existing operations successfully or to minimize any unforeseen operational difficulties could have a material adverse effect on our financial condition and results of operations. In addition, debt agreements impose certain limitations on our ability to enter into mergers or combination transactions and our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses.
A security interruption or failure with respect to our information technology systems could harm our ability to effectively operate our business.
Our ability to effectively manage and operate our business depends significantly on information technology systems. The failure of these systems to operate effectively and support our operations, challenges in transitioning to upgraded or replacement systems, difficulty in integrating new or updated systems, or a breach in security of these systems could adversely impact the operations of our business.
Any breach of our network may result in the loss of valuable business data, misappropriation of our customers’ or employees’ personal information, or a disruption of our business, which could harm our customer relationships and reputation, and result in lost revenues, fines or lawsuits.
Moreover, we must comply with increasingly complex and rigorous regulatory standards enacted to protect business and personal data. Any failure to comply with these regulatory standards could subject us to legal and reputational risks. Misuse of or failure to secure personal information could also result in violation of data privacy laws and regulations, proceedings against us by governmental entities or others, damage to our reputation and credibility, and could have a negative impact on revenues and profits.
Risks Related to Our Derivative Transactions, Debt and Access to Capital
Our derivative activities could result in financial losses or could reduce our earnings.
We may enter into derivative instrument contracts for a portion of our oil and natural gas production from time to time. As of December 31, 2021, we had entered into derivative contracts covering a portion of our projected oil and gas production through 2023 (refer to Note 7—Derivative Instruments under Part II, Item 8 of this Annual Report for a summary of our derivative instruments as of December 31, 2021). Accordingly, our earnings may fluctuate significantly as a result of changes in fair value of our derivative instruments.
Derivative instruments also expose us to the risk of financial loss in some circumstances, including when:
•production is less than the volume covered by the derivative instruments;
•there is an increase in the differential between the underlying price in the derivative instrument and actual prices received; or
32
•there are issues with regard to legal enforceability of such instruments.
The use of derivatives may, in some cases, require the posting of cash collateral with counterparties. If we enter into derivative instruments that require cash collateral and commodity prices or interest rates change in a manner adverse to us, our cash otherwise available for use in our operations would be reduced, which could limit our ability to make future capital expenditures and make payments on our indebtedness, and which could also limit the size of CRP’s borrowing base. Future collateral requirements will depend on arrangements with our counterparties, highly volatile commodity prices and interest rates. In addition, derivative arrangements could limit the benefit we would receive from increases in the prices for oil and natural gas, which could also have a material adverse effect on our financial condition.
Our commodity derivative contracts expose us to risk of financial loss if a counterparty fails to perform under a contract. Disruptions in the financial markets could lead to sudden decreases in a counterparty’s liquidity, which could make the counterparty unable to perform under the terms of the contract, and we may not be able to realize the benefit of the contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Even if we accurately predict sudden changes, our ability to negate the risk may be limited depending upon market conditions.
Since our production is not fully hedged, and we are also exposed to fluctuations in oil, natural gas and NGL prices as it relates to the price we receive from the sale of our unhedged volumes. We intend to continue to hedge a portion of our production, but we may not be able to do so at favorable prices. Accordingly, our revenues and cash flows are subject to increased volatility with regard to these unhedged volumes, and a decline in commodity prices could materially and adversely affect our business, financial condition and results of operations.
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, business prospects and our ability to make payments on our outstanding debt.
As of December 31, 2021, we had approximately $825.6 million of total long-term debt and additional borrowing capacity of $669.2 million under CRP’s revolving credit facility (after giving effect to $5.8 million of outstanding letters of credit ), all of which would be secured if borrowed. Subject to the restrictions in the instruments governing CRP’s outstanding indebtedness (including CRP’s revolving credit facility and senior notes), CRP and its subsidiaries may incur substantial additional indebtedness (including secured indebtedness) in the future. Although the instruments governing CRP’s outstanding indebtedness do contain restrictions on the incurrence of additional indebtedness, these restrictions will be subject to waiver and a number of significant qualifications and exceptions, and indebtedness incurred in compliance with these restrictions could be substantial.
Our current and future level of indebtedness could affect our operations in several ways, including the following:
•require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;
•limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;
•increase our vulnerability to downturns and adverse developments in our business and the economy generally;
•limit our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures, acquisitions, general corporate or other expenses or to refinance existing indebtedness;
•place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;
•make it more likely that a reduction in CRP’s borrowing base following a periodic redetermination could require CRP to repay a portion of its then-outstanding bank borrowings;
•make us vulnerable to increases in interest rates as the indebtedness under CRP’s revolving credit facility may vary with prevailing interest rates;
•place us at a competitive disadvantage relative to our competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; and
•make it more difficult for CRP to satisfy its obligations under its debt and increase the risk that we may default on its debt obligations.
We may not be able to generate sufficient cash to service all of CRP’s indebtedness and may be forced to take other actions to satisfy CRP’s obligations under applicable debt instruments, which may not be successful.
CRP’s ability to make scheduled payments on or to refinance its indebtedness depends on our financial condition and operating performance, which are subject to prevailing economic and competitive conditions and certain financial, business and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit CRP to pay the principal, premium, if any, and interest on CRP’s indebtedness.
33
If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. Our ability to restructure or refinance CRP’s indebtedness will depend on the condition of the capital markets and our financial condition at such time. Any refinancing of indebtedness could be at higher interest rates and may require CRP to comply with more onerous covenants, which could further restrict business operations. The terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm CRP’s ability to incur additional indebtedness. In the absence of sufficient cash flows and capital resources, we could face substantial liquidity problems and might be required to dispose of material assets or operations to meet debt service and other obligations. The agreements governing CRP’s indebtedness restrict CRP’s ability to dispose of assets and CRP’s use of the proceeds from such disposition. CRP may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit CRP to meet scheduled debt service obligations.
Restrictions in CRP’s existing and future debt agreements could limit our growth and ability to engage in certain activities.
CRP’s credit agreement and the indentures governing its senior notes contain a number of significant covenants, including restrictive covenants that may limit CRP’s ability to, among other things:
•incur additional indebtedness;
•make loans to others;
•make investments;
•merge or consolidate with another entity;
•make certain payments;
•hedge future production or interest rates;
•incur liens;
•sell assets; and
•engage in certain other transactions without the prior consent of the lenders.
In addition, CRP’s credit agreement requires us to maintain certain financial ratios or to reduce our indebtedness if we are unable to comply with such ratios. As of December 31, 2021, we were in full compliance with such financial ratios and covenants.
The restrictions in CRP’s debt agreements may also limit our ability to obtain future financings to withstand a future downturn in our business or the economy in general, or to otherwise conduct necessary corporate activities. We may also be prevented from taking advantage of business opportunities that arise because of the limitations that the restrictive imposed on CRP.
If CRP is unable to comply with the restrictions and covenants in the agreements governing its indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that CRP has borrowed.
Any default under the agreements governing CRP’s indebtedness that is not cured or waived by the required lenders, and the remedies sought by the holders of any such indebtedness, could make CRP unable to pay principal, premium, if any, and interest on such indebtedness. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest on CRP’s indebtedness, or if CRP otherwise fails to comply with the various covenants, including financial and operating covenants, in the agreements governing CRP’s indebtedness, CRP could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
•the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;
•the lenders under CRP’s revolving credit facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and
•we could be forced into bankruptcy or liquidation.
If our operating performance declines, we may in the future need to obtain waivers under CRP’s revolving credit facility to avoid CRP being in default. If CRP breaches the covenants under its revolving credit facility and seeks a waiver, CRP may not be able to obtain a waiver from the required lenders. If this occurs, CRP would be in default under the revolving credit facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
34
Any significant reduction in the borrowing base under CRP’s revolving credit facility as a result of the periodic borrowing base redeterminations or otherwise may negatively impact our ability to fund our operations.
CRP’s revolving credit facility limits the amounts CRP can borrow up to a borrowing base amount, which the lenders, in their sole discretion, determine semiannually in the spring and fall. The borrowing base depends on, among other things, projected revenues from, and asset values of, the oil and natural gas properties securing the loan. The borrowing base will automatically be decreased by an amount equal to 25% of the aggregate notional amount of permitted senior unsecured notes CRP may issue in the future. The lenders can unilaterally adjust the borrowing base and the borrowings permitted to be outstanding under CRP’s revolving credit facility. Any increase in the borrowing base requires the consent of the lenders holding 100% of the commitments. In connection with amending and restating the credit agreement in early 2022, the elected commitments were increased to $750 million.
In the future, we may not be able to access adequate funding under CRP’s revolving credit facility (or a replacement facility) as a result of a decrease in the borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations and the inability of other lenders to provide additional funding to cover the defaulting lender’s portion. Declines in commodity prices could result in a determination to lower the borrowing base in the future and, in such case, CRP could be required to repay any indebtedness in excess of the redetermined borrowing base. As a result, we may be unable to implement our respective drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service CRP’s indebtedness.
If we experience liquidity concerns, we could face a downgrade in our debt ratings which could restrict our access to, and negatively impact the terms of, current or future financings or trade credit.
Our ability to obtain financing and trade credit and the terms of any financing or trade credit is, in part, dependent on the credit ratings assigned to our debt by independent credit rating agencies. We cannot provide assurance that any of our current ratings will remain in effect for any given period of time or that a rating will not be lowered or withdrawn entirely by a rating agency if, in its judgment, circumstances so warrant. Factors that may impact our credit ratings include debt levels, planned asset purchases or sales and near-term and long-term production growth opportunities, liquidity, asset quality, cost structure, product mix and commodity pricing levels. A ratings downgrade could adversely impact our ability to access financings or trade credit and increase our borrowing costs.
Increases in interest rates could adversely affect our business.
Our business and operating results can be harmed by factors such as the availability, terms of and cost of capital, increases in interest rates or a reduction in credit rating. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. At December 31, 2021, we had $25.0 million in borrowings outstanding under CRP’s revolving credit facility. Interest is calculated under the terms of CRP’s credit agreement. Recent and continuing disruptions and volatility in the global financial markets may lead to a contraction in credit availability impacting our ability to finance operations. We require continued access to capital. A significant reduction in cash flows from operations or the availability of credit could materially and adversely affect our ability to achieve our planned growth and operating results.
Risks Related to Legislative and Regulatory Initiatives
Climate change laws and regulations restricting emissions of GHGs could increase our costs and reduced demand for the oil and natural gas that we produce, while potential physical effects of climate change could disrupt our production and cause us to incur significant costs in preparing for or responding to those effects.
The threat of climate change continues to attract considerable attention in the United States and around the world. Numerous proposals have been made and could continue to be made at the international, national, regional and state levels of government to monitor and limit existing emissions of GHGs as well as to restrict or eliminate such future emissions. For example, in response to findings that emissions of carbon dioxide, methane and other GHGs present an endangerment to public health and the environment, the EPA has adopted regulations pursuant to the CAA that, among other things, require PSD preconstruction and Title V operating permits for certain large stationary sources. While the regulation of methane from oil and gas facilities in the U.S. has been subject to uncertainty in recent years, President Biden signed an executive order in January 20, 2021 calling for the reinstatement or issuance of methane emissions standards for new, modified, and existing oil and gas facilities. The EPA subsequently proposed new regulations to establish comprehensive standards of performance and emission guidelines for methane and volatile organic compound emissions from new and existing operations in the oil and gas sector, but we cannot predict the scope of any final methane regulatory requirements or the cost to comply with such requirements. Compliance with these rules will likely require enhanced record-keeping practices, the purchase of new equipment, such as optical gas imaging instruments to detect leaks, increased frequency of maintenance and repair activities to address emissions leakage and additional personnel time to support these activities or the engagement of third-party contractors to assist with and verify compliance.
35
A separate executive order targeting climate change was issued by President Biden in January 2021, which directed the Secretary of the Interior to pause new oil and natural gas leasing on public lands and in offshore waters pending completion of a comprehensive review of the federal permitting and leasing practices, consider whether to adjust royalties associated with coal, oil, and gas resources extracted from public lands and offshore waters and identify any “fossil fuel subsidies” to take steps to ensure that federal funding is not directly subsidizing fossil fuels. Legal challenges to the executive orders have been filed, and we cannot predict the scope of any resulting legislation or new regulations.
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. President Biden announced in April 2021 a new, more rigorous nationally determined emissions reduction level of 50% to 52% from 2005 levels in economy-wide net GHG emissions by 2030. Moreover, the international community gathered again in Glasgow in November 2021 at the 26th Conference of the Parties (“COP26”), during which multiple announcements (not having the effect of law) were made, including a call for parties to eliminate certain fossil fuel subsidies and pursue further action on non-CO2 GHGs. Relatedly, the United States and European Union jointly announced at COP26 the launch of a Global Methane Pledge, an initiative which over 100 counties joined, committing to a collective goal of reducing global methane emissions by at least 30% from 2020 levels by 2030, including “all feasible reductions” in the energy sector. The impacts of these orders, pledges, agreements and any legislation or regulation promulgated to fulfill the United States’ commitments under the Paris Agreement, COP26, or other international conventions cannot be predicted at this time.
Please refer to Regulation of the Oil and Natural Gas Industry in Item 1 for further discussion on the topics referenced above and additional information on existing and proposed laws, regulations, treaties and international pledges intended to address GHGs and other climate change issues. Existing and future laws and regulations relating to climate change and GHG emissions could increase our costs, reduce demand for our products, limit our growth opportunities, impair our ability to develop our reserves and have other adverse effects on our business.
Federal, state and local legislative and regulatory initiatives relating to hydraulic fracturing as well as governmental reviews of such activities could result in increased costs and additional operating restrictions or delays in the completion of oil and natural gas wells and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, proppants and chemicals under pressure into targeted subsurface formations to fracture the surrounding rock and stimulate production. We regularly use hydraulic fracturing as part of our operations. Hydraulic fracturing is typically regulated by state oil and natural gas commissions, but the EPA and other federal agencies have asserted regulatory authority over aspects of the process. In addition, Congress has from time to time considered legislation to provide for federal regulation of hydraulic fracturing under the SDWA and to require disclosure of the chemicals used in the hydraulic fracturing process. It is unclear how any additional federal regulation of hydraulic fracturing activities may affect our operations.
Certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. The White House Council on Environmental Quality is coordinating an administration-wide review of hydraulic fracturing practices. Additionally, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The EPA report concluded that hydraulic fracturing activities have not led to widespread, systemic impacts on drinking water resources in the United States, although there are above-and-below ground mechanisms by which hydraulic fracturing activities have the potential to impact drinking water resources. Other governmental agencies, including the United States Department of Energy and the United States Department of the Interior, are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing under the federal SDWA or other regulatory mechanisms.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure and well construction requirements on hydraulic fracturing activities. For example, in May 2013, the Railroad Commission of Texas issued a “well integrity rule,” which updates the requirements for drilling, putting pipe down and cementing wells. The rule also includes new testing and reporting requirements, such as (i) the requirement to submit cementing reports after well completion or after cessation of drilling, whichever is later, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. The well integrity rule took effect in January 2014. Local governments also may seek to adopt ordinances within their jurisdictions regulating the time, place and manner of drilling activities in general or hydraulic fracturing activities in particular. We believe that we follow applicable standard industry practices and legal requirements for groundwater protection in our hydraulic fracturing activities. Nonetheless, if new or more stringent federal, state or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of development activities, and perhaps even be precluded from drilling wells.
36
Conservation measures, technological advances and negative shift in market perception toward oil and natural gas industry could reduce demand for oil and natural gas.
Fuel conservation measures, alternative fuel requirements, increasing consumer demand for alternatives to oil and natural gas, technological advances in fuel economy and energy generation devices could reduce demand for oil and natural gas. Additionally, the increased competitiveness of alternative energy sources (such as electric vehicles, wind, solar, geothermal, tidal, fuel cells and biofuels) could reduce demand for oil and natural gas and, therefore, our revenues.
Additionally, certain segments of the investor community have recently expressed negative sentiment towards investing in the oil and natural gas industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and natural gas representation in certain key equity market indices. Some investors, including certain pension funds, university endowments and family foundations, have stated policies to reduce or eliminate their investments in the oil and natural gas sector based on social and environmental considerations. Furthermore, certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects.
The impact of the changing demand for oil and natural gas, together with a change in investor sentiment, may have a material adverse effect on our business, financial condition, results of operations and cash flows.
Our operations may be exposed to significant delays, costs and liabilities as a result of environmental and occupational health and safety requirements applicable to our business activities.
Our operations are subject to stringent, complex and evolving federal, state and local laws and regulations governing the discharge of materials into the environment, health and safety aspects of our operations or otherwise relating to environmental protection. These laws and regulations may impose numerous obligations applicable to our operations, including the acquisition of a permit or other approval before conducting regulated activities; the restriction of types, quantities and concentration of materials that can be released into the environment; the limitation or prohibition of drilling activities on certain lands lying within wilderness, wetlands and other protected areas; the application of specific health and safety criteria addressing worker protection; and the imposition of substantial liabilities for pollution resulting from our operations. Numerous governmental authorities, such as the EPA and analogous state agencies, have the power to enforce compliance with these laws and regulations and the permits issued under them. Such enforcement actions often involve taking difficult and costly compliance measures or corrective actions. Failure to comply with these laws and regulations may result in the assessment of sanctions, including administrative, civil or criminal penalties, natural resource damages, the imposition of investigatory or remedial obligations, and the issuance of orders limiting or prohibiting some or all of our operations. In addition, we may experience delays in obtaining, or be unable to obtain, required permits, which may delay or interrupt our operations and limit our growth and revenue.
Certain environmental laws impose strict joint and several liability for costs required to remediate and restore sites where hazardous substances, hydrocarbons or solid wastes have been stored or released. We may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In connection with certain acquisitions, we could acquire, or be required to provide indemnification against, environmental liabilities that could expose us to material losses. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Our insurance may not cover all environmental risks and costs or may not provide sufficient coverage if an environmental claim is made against us. Moreover, public interest in the protection of the environment has increased dramatically in recent years. The trend of more expansive and stringent environmental legislation and regulations applied to the crude oil and natural gas industry could continue, resulting in increased costs of doing business and consequently affecting profitability. In the states of New Mexico and Texas, as an example, governmental authorities are investigating the practice of flaring natural gas and it is possible that such states could implement additional volumetric or other restrictions on this practice which may require us to curtail or shut in production which otherwise is or would be flared due to the unavailability of acceptable delivery, transportation or processing arrangements. To the extent laws are enacted or other governmental action is taken that restricts drilling or imposes more stringent and costly operating, waste handling, disposal and cleanup requirements, our business, prospects, financial condition or results of operations could be materially adversely affected.
37
Restrictions on drilling activities intended to protect certain species of wildlife may adversely affect our ability to conduct drilling activities in areas where we operate.
Oil and natural gas operations in our operating areas may be adversely affected by seasonal or permanent restrictions on drilling activities designed to protect various wildlife. Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations or materially increase our operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our activities that could have a material and adverse impact on our ability to develop and produce our reserves.
Tax laws and regulations may change over time, and any such changes could adversely affect our business and financial condition.
From time to time, legislation has been proposed that, if enacted into law, would make significant changes to U.S. federal and state income tax laws affecting the oil and natural gas industry, including (i) eliminating the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. These proposed changes in the U.S. tax law, if adopted, or other similar changes that would impose additional tax on our activities or reduce or eliminate deductions currently available with respect to natural gas and oil exploration, development or similar activities, could adversely affect our business, results of operations, financial condition and cash flow.
Changes in laws or regulations, or a failure to comply with any laws and regulations, may adversely affect our business, investments and results of operations.
We are subject to laws, regulations and rules enacted by national, regional and local governments and NASDAQ. In particular, we are required to comply with certain SEC, NASDAQ and other legal or regulatory requirements. Compliance with, and monitoring of, applicable laws, regulations and rules may be difficult, time consuming and costly. Those laws, regulations and rules and their interpretation and application may also change from time to time and those changes could have a material adverse effect on our business, investments and results of operations. In addition, a failure to comply with applicable laws, regulations and rules, as interpreted and applied, could have a material adverse effect on our business and results of operations
Risks Related to Our Common Stock and Capital Structure
A negative shift in investor sentiment towards the oil and gas industry could adversely affect our ability to raise equity and debt capital.
Certain segments of the investor community have recently developed negative sentiment towards investing in the oil and gas industry. Over the past years, equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. Some investors, including certain institutional investors, private equity companies, pension funds, university endowments and family foundations have stated policies to reduce or eliminate their investments in the oil and gas sector based on social and environment considerations. Certain other stakeholders have pressured commercial and investment banks to stop funding oil and gas projects. Such developments could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also result in a reduction of available capital funding for potential development projects, further impacting our future financial results.
Riverstone own a significant percentage of our outstanding voting common stock.
Riverstone Investment Group LLC and its affiliates (“Riverstone”) beneficially own approximately 31% of our voting common stock as of December 31, 2021. As long as Riverstone own or control a significant percentage of outstanding voting power, they may have the ability to strongly influence all corporate actions requiring stockholder approval, including the election and removal of directors and the size of our board of directors, any amendment of our third amended and restated certificate of incorporation (the “Charter”) or our second amended and restated bylaws (the “Bylaws”), or the approval of any merger or other significant corporate transaction, including a sale of substantially all of our assets.
The interests of Riverstone may not align with the interests of our other stockholders. Riverstone is in the business of making investments in companies and may acquire and hold interests in businesses that compete directly or indirectly with us. Riverstone may also pursue acquisition opportunities that may be complementary to our business, and, as a result, those acquisition opportunities may not be available to us. In addition, our Charter provides that we renounce any interest or expectancy in the
38
business opportunities of our officers and directors and their respective affiliates and each such party shall not have any obligation to offer us those opportunities unless presented to one of our directors or officers in his or her capacity as a director or officer.
The declaration of dividends and any repurchases of our common stock are each within the discretion of our board of directors based upon a review of relevant considerations, and there is no guarantee that we will pay any dividends on or repurchase shares of our common stock in the future or at levels anticipated by our stockholders.
Dividends, whether fixed or variable, and stock repurchases are authorized and determined by our board of directors in its sole discretion and depend upon a number of factors, including the Company’s financial results, cash requirements and future prospects, restrictions in our debt agreements, as well as such other factors deemed relevant by our board of directors. In February 2022, we announced a $350 million stock repurchase program, but this repurchase program may be suspended from time to time, modified, extended or discontinued by our board of directors at any time. Similarly, any dividends, whether fixed or variable, we may declare in the future will be determined by our board of directors in its sole discretion. Any elimination of, or downward revision in, our stock repurchase program or dividend policy could have an adverse effect on the market price of our common stock.
Provisions contained in our Charter and Bylaws, as well as provisions of Delaware law, could impair a takeover attempt, which may adversely affect the market price of our Common Stock.
Our Charter and Bylaws contain provisions that could have the effect of delaying or preventing changes in control or changes in our management without the consent of our board of directors. These provisions include:
•a classified board of directors, with only approximately one-third of our board of directors elected each year;
•no cumulative voting in the election of directors, which limits the ability of minority stockholders to elect director candidates;
•the exclusive right of our board of directors to elect a director to fill a vacancy created by the expansion of the board of directors or the resignation, death, or removal of a director, which prevents stockholders from being able to fill vacancies on our board of directors;
•the ability of our board of directors to determine whether to issue shares of our preferred stock and to determine the price and other terms of those shares, including preferences and voting rights, without stockholder approval, which could be used to significantly dilute the ownership of a hostile acquirer;
•a prohibition on stockholder action by written consent, which forces stockholder action to be taken at an annual or special meeting of our stockholders;
•the requirement that an annual meeting of stockholders may be called only by the chairman of the board of directors, the chief executive officer, or the board of directors, which may delay the ability of our stockholders to force consideration of a proposal or to take action, including the removal of directors;
•limiting the liability of, and providing indemnification to, our directors and officers;
•controlling the procedures for the conduct and scheduling of stockholder meetings;
•providing that directors may be removed prior to the expiration of their terms by stockholders only for cause; and
•advance notice procedures that stockholders must comply with in order to nominate candidates to our board of directors or to propose matters to be acted upon at a stockholders’ meeting, which may discourage or deter a potential acquirer from conducting a solicitation of proxies to elect the acquirer’s own slate of directors or otherwise attempting to obtain control of the Company.
These provisions, alone or together, could delay hostile takeovers and changes in control of the Company or changes in our board of directors and management.
As a Delaware corporation, we are also subject to provisions of Delaware law, including Section 203 of the Delaware General Corporation Law, which prevents some stockholders holding more than 15% of our outstanding voting common stock from engaging in certain business combinations without approval of the holders of substantially all of our outstanding voting common stock. Any provision of our Charter or Bylaws or Delaware law that has the effect of delaying or deterring a change in control could limit the opportunity for our stockholders to receive a premium for their securities and could also affect the price that some investors are willing to pay for our securities.
ITEM 1B. UNRESOLVED STAFF COMMENTS
None.
39
ITEM 3. LEGAL PROCEEDINGS
Refer to Note 13—Commitments and Contingencies under Part II, Item 8 of this Annual Report for more information regarding our legal proceedings.
ITEM 4. MINE SAFETY DISCLOSURE
Not applicable.
PART II
ITEM 5. MARKET FOR REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES
Common Stock
Our Class A common stock (“Common Stock”) is currently quoted on NASDAQ under the symbol “CDEV.” As of February 18, 2022, there were 17 registered holders of record of our Common Stock.
Stock Repurchase Program
In February 2022, our Board of Directors authorized a stock repurchase program to acquire up to $350 million of our outstanding Common Stock (the “Repurchase Program”), which is approved to run through April 1, 2024. We intend to use the Repurchase Program to reduce our shares of Common Stock outstanding and plan to fund these repurchases with cash on hand and cash flows from operations. Repurchases may be made from time to time in the open market or via privately negotiated transactions at our discretion, and they will be subject to market conditions, applicable legal requirements, available liquidity, compliance with our debt and other agreements and other factors. The Repurchase Program does not require any specific number of shares to be acquired and can be modified or discontinued by our Board of Directors at any time.
Dividend Policy
We have not paid any cash dividends on our Common Stock to date. Our board of directors may from time to time consider whether or not to institute a dividend policy. It is our present intention to retain any earnings for use in our business operations or Repurchase Program and, accordingly, we do not at this time anticipate the board of directors declaring any cash dividends in the near future.
ITEM 6. [Reserved]
40
ITEM 7. MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS
The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying consolidated financial statements and related notes in “Item 8. Financial Statements and Supplementary Data” in this Annual Report. The following discussion and analysis contains forward-looking statements that reflect our future plans, estimates, beliefs and expected performance. The forward-looking statements are dependent upon events, risks and uncertainties that may be outside our control. Our actual results could differ materially from those discussed in these forward-looking statements. Factors that could cause or contribute to such differences include, but are not limited to, future market prices for oil, natural gas and NGLs, future production volumes, estimates of proved reserves, capital expenditures, economic and competitive conditions, inflation, regulatory changes, continued and future impacts of COVID-19 and other uncertainties, as well as those factors discussed in “Cautionary Statement Concerning Forward-Looking Statements” and “Item 1A. Risk Factors” in this Annual Report, all of which are difficult to predict. In light of these risks, uncertainties and assumptions, the forward-looking events discussed may not occur. We do not undertake any obligation to publicly update any forward-looking statements except as otherwise required by applicable law.
Overview
We are an independent oil and natural gas company focused on the development of crude oil and associated liquids-rich natural gas reserves in the Permian Basin. Our assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin. Our capital programs are focused on projects that we believe provide the highest return on capital.
Market Conditions
The 2020 worldwide outbreak of COVID-19, the uncertainty regarding its impact and various governmental actions taken to mitigate the effects of COVID-19 resulted in an unprecedented decline in the demand for oil and natural gas throughout 2020. In addition, the decision by Saudi Arabia to drastically reduce export prices and increase oil production in March 2020 (the “Saudi-Russia oil price war”) followed by curtailment agreements among Organization of Petroleum Exporting Countries (“OPEC”) and other countries such as Russia further increased uncertainty and volatility around global oil supply-demand dynamics. However, in April of 2020, the members of OPEC and other oil producing countries (“OPEC+”) agreed to reduce their crude oil production throughout the year, while U.S. producers substantially reduced or suspended drilling and completion activity due to low oil prices and poor economics.
The demand for oil and natural gas continued to remain low in early 2021 due to continued uncertainty regarding the impacts of COVID-19. OPEC+ extended their production cuts through the first quarter of 2021 and began to gradually increase output during the second quarter of 2021 with more substantial output increases announced from August 2021 through September 2022. U.S. drilling activity began to increase in the fourth quarter of 2020 and has continued to increase steadily since. These factors have led to a gradual increase in oil and gas supply but has not returned global supply to pre-pandemic levels. Meanwhile, the global demand for oil and gas has risen steadily throughout 2021 and has outpaced supply growth due to the availability of COVID-19 vaccinations, increased mobility due to less governmental mandated restrictions and the global transition away from coal to natural gas. As a result of this imbalance, global oil inventories have continued to decline throughout 2021 and are currently below pre-pandemic levels. These factors, among others, have aided in the recovery of global commodity prices during 2021. Specifically, WTI spot prices for crude oil reached a high of $84.65 per barrel on October 26, 2021 from a low of negative $37.63 per barrel on April 20, 2020 (which was due to depressed demand and insufficient storage capacity, particularly at the WTI physical settlement location in Cushing, Oklahoma). Similarly, the average Henry Hub index price for natural gas reached $4.74 during the fourth quarter of 2021, which was more than double of the average Henry Hub price of $1.99 for the year ended December 31, 2020.
The oil and natural gas industry is cyclical, and it is likely that commodity prices will continue to be volatile due to fluctuations in global supply and demand, inventory levels, the continued effects from COVID-19 and variant strains of the virus, geopolitical events, federal and state government regulations, weather conditions, the global transition to alternative energy sources, supply chain constraints and other factors. The following table highlights the quarterly average NYMEX price trends for crude oil and natural gas since the first quarter of 2019:
| 2019 | 2020 | 2021 | |||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | Q1 | Q2 | Q3 | Q4 | ||||||||||||||||||||||||||||||||||||||||||||||||||||||||||||
| Crude Oil (per Bbl) | $ | 54.90 | $ | 59.81 | $ | 56.45 | $ | 56.94 | $ | 46.19 | $ | 28.00 | $ | 40.93 | $ | 42.66 | $ | 57.84 | $ | 66.06 | $ | 70.56 | $ | 77.09 | |||||||||||||||||||||||||||||||||||||||||||||||
| Natural Gas (per MMBtu) | $ | 2.88 | $ | 2.51 | $ | 2.33 | $ | 2.34 | $ | 1.88 | $ | 1.65 | $ | 1.95 | $ | 2.47 | $ | 3.44 | $ | 2.88 | $ | 4.28 | $ | 4.74 | |||||||||||||||||||||||||||||||||||||||||||||||
Lower commodity prices (including our realized differentials) and lower futures curves for oil and gas prices can also result in impairments of our proved oil and natural gas properties or undeveloped acreage (such as the impairments incurred in the first quarter of 2020) and may materially and adversely affect our future business, financial condition, results of operations, operating
41
cash flows, liquidity and/or ability to finance planned capital expenditures. Lower realized prices may also reduce the borrowing base under CRP’s credit agreement, which is determined at the discretion of the lenders and is based on the collateral value of our proved reserves that have been mortgaged to the lenders. Upon a redetermination, if any borrowings in excess of the revised borrowing capacity were outstanding, we could be forced to immediately repay a portion of the debt outstanding under the credit agreement. Additionally, a lower price environment and its impact to our operations could impact our ability to comply with the covenants under our credit agreement and senior notes.
The oil and gas industry is cyclical, and the demand for oilfield goods and services, as well as other inflationary factors in the economy, can put pressure on the pricing structure within our industry. As commodity prices rise, the cost of oilfield goods and services generally also increase, while during periods of commodity price declines, oilfield costs typically lag and do not adjust downward as fast as oil prices do. Further, the U.S. inflation rate has been steadily increasing during 2021 and into 2022. These inflationary pressures could also result in increases to the costs of our materials, services and personnel, which would in turn cause our capital expenditures and operating costs to go up.
COVID-19 Outbreak
The COVID-19 outbreak and its development into a pandemic in March 2020 have required that we take precautionary measures intended to help minimize the risk to our business, employees, customers, vendors, suppliers and the communities in which we operate. Our operational employees have been and are currently able to work on site, while certain non-operational employees have been working remotely part-time and reporting to our offices on a limited basis. We have taken various precautionary measures with respect to our operational employees, direct contractors and employees who returned to our offices or job sites such as (i) requesting that they have not experienced any symptoms consistent with COVID-19, or been in close contact with someone showing such symptoms, before reporting to the work site or office, (ii) self-quarantining any employees or contractors who have shown signs or symptoms of COVID-19 (regardless of whether such person has been confirmed to be infected), (iii) imposing certain mask and social distancing requirements on work sites and at our offices, and (iv) encouraging all employees and contractors to follow the Center of Disease Control (the “CDC”) recommended preventive measures (including those mentioned above) to limit the spread of COVID-19. We have continued to update our safety protocols in alignment with CDC guidance and governmental mandates, and have been able to reduce some requirements if employees, customers, vendors, or suppliers are fully vaccinated. We have not experienced any significant operational disruptions (including disruptions from our suppliers or service providers) as a result of the COVID-19 outbreak.
2021 Highlights and Future Considerations
Operational Highlights
We operated a two-rig drilling program during 2021, which enabled us to complete and bring online 42 gross operated wells with an average effective lateral length of approximately 8,900 feet.
In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that caused multi-day electrical outages and shortages, pipeline and infrastructure freezes, and transportation disruptions. These events led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time, and our operations were also impacted by a partial shut-in of certain wells and their associated production for about seven days during the event. Refer to the discussion below for the current impacts from Winter Storm Uri on our results of operations during the year ended December 31, 2021.
Divestiture Highlights
On December 1, 2021, we completed the sale of approximately 6,200 net leasehold acres for an unadjusted sales price of $101 million. The divested assets represent non-core acreage that was mainly undeveloped but which also contained 20 low producing wells located on the southernmost portion of our acreage position in Reeves County, Texas. The properties divested consisted of 5,830 MBoe of proved reserves as of December 31, 2020, representing approximately 2% of our proved reserves as of that date, and generated approximately 1,600 Boe/d (64% oil) during the third quarter of 2021. Net proceeds from the sale were used to repay a portion of our borrowings outstanding under CRP’s revolving credit facility, reducing the outstanding balance to $25.0 million as of December 31, 2021.
42
Financing Highlights
On March 19, 2021, we issued $150.0 million of 3.25% senior convertible notes due 2028 (the “Convertible Senior Notes”) in a public offering. On March 26, 2021, an additional $20.0 million of Convertible Senior Notes were issued pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. The issuance resulted in net proceeds of $163.6 million, after deducting debt issuance costs of $6.4 million, and such proceeds were used to fund the cost of entering into capped call spread transactions totaling $14.7 million and to repay borrowings outstanding under CRP’s revolving credit facility. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million), which was the intended use of proceeds from the Convertible Senior Notes offering.
On February 18, 2022, we closed on a new five-year revolving credit facility, which replaced our previous credit agreement that was set to mature on May 4, 2023. The elected commitments under the new credit facility increased to $750 million from $700 million under our previous facility, and the borrowing base increased to $1.15 billion from $700 million previously. The new credit facility will mature in February 2027.
In February 2022, our Board of Directors authorized the Repurchase Program to acquire up to $350 million of our outstanding Common Stock, and the program is approved to run through April 1, 2024. We intend to use the Repurchase Program to reduce shares of our Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flows from operations.
43
Results of Operations
For the Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020
The following table provides the components of our net revenues and net production (net of all royalties, overriding royalties and production due to others) for the periods indicated, as well as each period’s average prices and average daily production volumes:
| Year Ended December 31, | Increase/(Decrease) | ||||||||||||||||||||||
| 2021 | 2020 | $ | % | ||||||||||||||||||||
| Net revenues (in thousands): | |||||||||||||||||||||||
| Oil sales | $ | 743,069 | $ | 475,694 | $ | 267,375 | 56 | % | |||||||||||||||
| Natural gas sales | 149,478 | 46,776 | 102,702 | 220 | % | ||||||||||||||||||
| NGL sales | 137,345 | 57,986 | 79,359 | 137 | % | ||||||||||||||||||
Oil and gas sales | $ | 1,029,892 | $ | 580,456 | $ | 449,436 | 77 | % | |||||||||||||||
| Average sales price: | |||||||||||||||||||||||
| Oil (per Bbl) | $ | 63.50 | $ | 36.02 | $ | 27.48 | 76 | % | |||||||||||||||
| Effect of derivative settlements on average price (per Bbl) | (10.19) | (3.15) | (7.04) | (223) | % | ||||||||||||||||||
| Oil net of hedging (per Bbl) | $ | 53.31 | $ | 32.87 | $ | 20.44 | 62 | % | |||||||||||||||
Average NYMEX price for oil (per Bbl) | $ | 67.89 | $ | 39.44 | $ | 28.45 | 72 | % | |||||||||||||||
Oil differential from NYMEX | (4.39) | (3.42) | (0.97) | (28) | % | ||||||||||||||||||
| Natural gas (per Mcf) | $ | 3.67 | $ | 1.13 | $ | 2.54 | 225 | % | |||||||||||||||
| Effect of derivative settlements on average price (per Mcf) | (0.32) | (0.12) | (0.20) | (167) | % | ||||||||||||||||||
| Natural gas net of hedging (per Mcf) | $ | 3.35 | $ | 1.01 | $ | 2.34 | 232 | % | |||||||||||||||
| Average NYMEX price for natural gas (per Mcf) | $ | 3.84 | $ | 1.99 | $ | 1.85 | 93 | % | |||||||||||||||
Natural gas differential from NYMEX | (0.17) | (0.86) | 0.69 | 80 | % | ||||||||||||||||||
| NGL (per Bbl) | $ | 36.61 | $ | 12.91 | $ | 23.70 | 184 | % | |||||||||||||||
Net production: | |||||||||||||||||||||||
| Oil (MBbls) | 11,701 | 13,207 | (1,506) | (11) | % | ||||||||||||||||||
| Natural gas (MMcf) | 40,741 | 41,302 | (561) | (1) | % | ||||||||||||||||||
| NGL (MBbls) | 3,752 | 4,490 | (738) | (16) | % | ||||||||||||||||||
Total (MBoe)(1) | 22,243 | 24,581 | (2,338) | (10) | % | ||||||||||||||||||
Average daily net production: | |||||||||||||||||||||||
| Oil (Bbls/d) | 32,058 | 36,084 | (4,026) | (11) | % | ||||||||||||||||||
| Natural gas (Mcf/d) | 111,619 | 112,848 | (1,229) | (1) | % | ||||||||||||||||||
| NGL (Bbls/d) | 10,278 | 12,269 | (1,991) | (16) | % | ||||||||||||||||||
Total (Boe/d)(1) | 60,939 | 67,161 | (6,222) | (9) | % | ||||||||||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
Oil, Natural Gas and NGL Sales Revenues. Total net revenues for the year ended December 31, 2021 increased by $449.4 million, or 77%, compared to the year ended December 31, 2020. Revenues are a function of oil, natural gas and NGL volumes sold and average commodity prices realized.
Average realized sale prices for oil, residue gas and NGLs increased for the year ended December 31, 2021 as compared to 2020 by 76%, 225%, and 184%, respectively. The 76% increase in the average realized oil price was mainly the result of higher (72%) NYMEX crude prices between periods, which was minimally offset by wider oil differentials ($0.97 per Bbl wider). The average realized sales price of natural gas increased 225% due to higher (93%) average NYMEX gas prices between periods, as well as improved gas differentials (by $0.69 per Mcf). The 184% increase in average realized NGL prices between periods was primarily attributable to higher Mont Belvieu spot prices for plant products in 2021 compared to 2020. The market prices for oil, natural gas and NGLs have all been impacted by higher global demand for oil and gas compared to 2020, when prices decreased significantly beginning in March 2020 as a result of COVID-19 and supply disruptions from the Russia-Saudi oil price war as discussed in the market conditions section above. Additionally, the first quarter 2021 realized price for natural gas in the Permian
44
Basin was impacted by Winter Storm Uri, which caused gas pipeline and supply disruptions and resulted in significant increases in Permian natural gas prices during this period.
Net production volumes for oil, natural gas, and NGLs decreased 11%, 1% and 16%, respectively, between periods. The oil production volume decrease was primarily related to normal production decline across our existing wells and temporary shut-ins of our wells during mid-February as a result of Winter Storm Uri. Oil volume declines for the year ended December 31, 2021, were further impacted by the suspension of our drilling and completion activity for several months during 2020 due to the drastic decline in oil prices discussed above. As a result, only 31 wells were completed in 2020, and we therefore entered 2021 producing just 28,550 Bbls/d of oil, as compared to the 84 wells we completed in 2019, which enabled us to enter 2020 producing 47,927 Bbls/d of crude oil. This 40% decline in exit rates was partially offset by our 2021 development program that placed 42 wells online during the year and thereby added 3,490 MBbls of oil to our 2021 annual production volumes. Natural gas and NGLs are produced concurrently with our crude oil volumes, typically resulting in a high correlation between fluctuations in our oil quantities sold and our natural gas and NGL quantities sold. However, during 2021, the main processor of our raw gas operated in full ethane-rejection, as compared to operating in partial ethane-recovery during 2020. Additionally, the amount of gas flared as a percentage of wellhead gas produced was significantly less during the year ended December 31, 2021, as compared to the year ended December 31, 2020. Both of these factors combined resulted in an increase in the amount of natural gas recovered and sold from our wet gas stream between periods, while the aforementioned variations in ethane-rejection between periods resulted in fewer NGLs being recovered during 2021.
Operating Expenses. The following table sets forth selected operating expense data for the periods indicated:
| Year Ended December 31, | Increase/(Decrease) | ||||||||||||||||||||||
| 2021 | 2020 | Change | % | ||||||||||||||||||||
| Operating costs (in thousands): | |||||||||||||||||||||||
| Lease operating expenses | $ | 106,419 | $ | 109,282 | $ | (2,863) | (3) | % | |||||||||||||||
| Severance and ad valorem taxes | 67,140 | 39,417 | 27,723 | 70 | % | ||||||||||||||||||
| Gathering, processing, and transportation expense | 85,896 | 71,309 | 14,587 | 20 | % | ||||||||||||||||||
| Operating cost metrics: | |||||||||||||||||||||||
| Lease operating expenses (per Boe) | $ | 4.78 | $ | 4.45 | $ | 0.33 | 7 | % | |||||||||||||||
| Severance and ad valorem taxes (% of revenue) | 6.5 | % | 6.8 | % | (0.3) | % | (4.0) | % | |||||||||||||||
| Gathering, processing, and transportation expense (per Boe) | 3.86 | 2.90 | 0.96 | 33 | % | ||||||||||||||||||
Lease Operating Expenses. Lease operating expenses (“LOE”) for the year ended December 31, 2021 decreased $2.9 million compared to the year ended December 31, 2020. Lower LOE for 2021 was primarily related to (i) a $2.9 million decrease in workover expense between periods; (ii) decreases in electricity costs in 2021 as a result of credits realized in the current year related to Winter Storm Uri; (iii) lower well operating expenses due to cost reduction initiatives, which included moving multiple wells off generator to lower cost line-power and switching wells away from electric submersible pumps to more reliable and cost-efficient gas lift; and (iv) lower variable and semi-variable costs stemming from the 10% production decline between periods. These decreases were partially offset by higher chemical costs, environmental and preventative maintenance expenses, and other fixed and variable costs associated with our higher well count, which increased to 404 gross operated horizontal wells as of December 31, 2021 from 386 gross operated horizontal wells as of December 31, 2020.
LOE per Boe was $4.78 for the year ended December 31, 2021, which represents an increase of $0.33 per Boe (or 7%) from 2020. This increase was primarily driven by per BOE cost increases between periods associated with fixed and semi-variable costs that don’t decrease at the same rate as declines in production, such as monthly rental fees for compressors and other equipment, wellhead chemical costs, and water handling fees. In addition, environmental expenses and preventative maintenance costs were higher for the year ended December 31, 2021 as compared to the same prior year period. These increases were partially offset by the lower level of workover activity in 2021, decreased electricity costs, and the cost reduction initiatives we have undertaken, as discussed above.
Severance and Ad Valorem Taxes. Severance and ad valorem taxes for the year ended December 31, 2021 increased $27.7 million compared to the year ended December 31, 2020. Severance taxes are primarily based on the market value of our production at the wellhead, while ad valorem taxes are generally based on the assessed taxable value of proved developed oil and natural gas properties and vary across the different counties in which we operate. Severance taxes for the year ended 2021 increased $31.3 million compared to the same 2020 period primarily due to higher oil, natural gas and NGL revenues between periods. These increases were partially offset by a $3.6 million decrease in ad valorem taxes between periods due to lower tax assessments on our oil and gas reserve values.
45
Severance and ad valorem taxes as a percentage of total net revenues decreased to 6.5% for the year ended December 31, 2021 as compared to 6.8% for the year ended December 31, 2020 as a result of the lower 2021 ad valorem tax assessments discussed above.
Gathering, Processing and Transportation Expenses. Gathering, processing and transportation costs (“GP&T”) for the year ended December 31, 2021 increased $14.6 million compared to the year ended December 31, 2020. On a per Boe basis, GP&T likewise increased 33% from $2.90 for the year ended December 31, 2020 to $3.86 per Boe for the year ended December 31, 2021. These increases were mainly attributable to (i) higher gas plant processing costs, whose variable fee portion is based on natural gas and NGL prices, both of which increased substantially between periods as discussed above, and (ii) a $2.9 million decrease in reimbursements received from third parties for their usage of our available firm transport capacity.
Depreciation, Depletion and Amortization. The following table summarizes our depreciation, depletion and amortization (“DD&A”) for the periods indicated:
| Year Ended December 31, | |||||||||||
| (in thousands, except per Boe data) | 2021 | 2020 | |||||||||
| Depreciation, depletion and amortization | $ | 289,122 | $ | 358,554 | |||||||
| Depreciation, depletion and amortization per Boe | $ | 13.00 | $ | 14.59 | |||||||
For the year ended December 31, 2021, DD&A expense amounted to $289.1 million, a decrease of $69.4 million from 2020. Lower DD&A expense in 2021 was due to i) the decline in DD&A rates between periods which decreased DD&A expense by $35.3 million, and ii) the decline in our overall production volumes between periods that lowered DD&A expense by $34.1 million from year to year.
Our DD&A rate can fluctuate as a result of finding and development costs incurred, acquisitions, impairments, as well as changes in proved developed and proved undeveloped reserves. DD&A per Boe was $13.00 for the year ended December 31, 2021 compared to $14.59 in 2020. This decrease in DD&A rate was primarily due to (i) the proved property impairment recognized in the first quarter of 2020, which lowered the carrying value of our depletion base by $591.8 million; (ii) net upward revisions in our proved developed reserves of 4.5 MMBoe for the year ended December 31, 2021 mainly related to higher SEC reserve pricing; and (iii) lower drilling and completion costs per lateral foot in 2021 versus 2020.
Impairment and Abandonment Expense. For the year ended December 31, 2021, $32.5 million of impairment and abandonment expense was incurred related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties.
For the year ended December 31, 2020, $691.2 million of impairment and abandonment expense was incurred related to certain of our oil and gas properties. This expense consisted of (i) a $591.8 million non-cash impairment of our proved properties in the first quarter of 2020 as a result of the depressed NYMEX oil and gas futures curves as of March 31, 2020; (ii) $78.8 million related to the amortization of leasehold expiration costs associated with individually insignificant unproved properties, and (iii) a $20.6 million write-off of individually significant leasehold acreage costs for acres that are not currently included in our future development plan.
Exploration and Other Expenses. The following table summarizes exploration and other expenses for the periods indicated:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Geological and geophysical costs | $ | 3,508 | $ | 4,533 | |||||||
| Stock-based compensation - equity awards | 1,883 | 1,433 | |||||||||
| Stock-based compensation - liability awards | (89) | 90 | |||||||||
| Stock-based compensation - cash settled awards | 314 | — | |||||||||
| Exploratory dry hole costs | — | 6,615 | |||||||||
| Rig termination fees | — | 3,046 | |||||||||
| Severance payments | — | 722 | |||||||||
| Other expenses | 2,267 | 1,916 | |||||||||
| Exploration and other expenses | $ | 7,883 | $ | 18,355 | |||||||
46
Exploration and other expenses were $7.9 million for the year ended December 31, 2021 compared to $18.4 million for the year ended December 31, 2020. Exploration and other expenses mainly consist of topographical studies, geographical and geophysical (“G&G”) projects, salaries and expenses of G&G personnel and include other operating costs. The period over period decrease was primarily related to charges incurred in 2020 that did not reoccur in 2021 including: (i) $6.6 million in exploratory dry hole costs; (ii) rig termination fees of $3.0 million recognized in 2020 when we reduced our drilling program from five rigs to none; (iii) $1.7 million in environmental remediation costs; and (iv) $0.7 million in severance payments to G&G employees. Additionally, for the year ended December 31, 2021 there was $1.0 million in lower ongoing G&G personnel costs compared to the year ended December 31, 2020 due to the decrease in headcount related to our 2020 workforce reduction. These decreases were partially offset by $1.3 million in nonrecurring costs incurred in 2021 associated with a sulfur clean-out of a third party’s processing facility and an increase in total stock-based compensation costs incurred during the year ended December 31, 2021 related to restricted stock units that became fully vested during the period as discussed below.
General and Administrative Expenses. The following table summarizes our general and administrative (“G&A”) expenses for the periods indicated:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Cash general and administrative expenses | $ | 48,269 | $ | 46,356 | |||||||
| Stock-based compensation - equity awards | 35,658 | 19,533 | |||||||||
| Stock-based compensation - liability awards | 20,662 | 3,512 | |||||||||
| Stock-based compensation - cash settled awards | 5,865 | — | |||||||||
| Severance payments | — | 3,466 | |||||||||
| General and administrative expenses | $ | 110,454 | $ | 72,867 | |||||||
G&A expenses for the year ended December 31, 2021 were $110.5 million compared to $72.9 million for the year ended December 31, 2020. Higher G&A in 2021 was the result of a $39.1 million increase in total stock-based compensation expense between periods. This increase was primarily related to a portion of our liability-classified restricted stock units, held by certain officers (non-NEOs) and employees, becoming fully vested following a maximum return event that was triggered in the third quarter of 2021. These awards were settled one-third in cash ($5.9 million) and two-thirds in equity, resulting in an aggregate charge of $21.4 million being recognized during the year ended December 31, 2021. There was an additional $20.5 million increase in total stock-based compensation related to liability-classified performance stock units granted in July 2020 that were outstanding for the entire year and which had a higher fair value as of December 31, 2021, as their fair value is required to be re-measured at each period end date. Refer to Note 6—Stock-Based Compensation under Part II, Item 8 of this Annual Report for additional information regarding these awards and the maximum return event. These increases were partially offset by $3.5 million in severance payments to G&A employees in the 2020 period that did not reoccur in 2021.
Net Gain (Loss) on Sale of Long-Lived Assets. During the year ended December 31, 2021, we completed the sale of approximately 6,200 net leasehold acres for an unadjusted sales price of $101 million. This divestiture represented the sale of an entire field, which resulted in a net gain on sale of $33.9 million. Refer to Note 2—Property Divestitures under Part II, Item 8 of this Annual Report for additional information.
Other Income and Expense.
Interest Expense. The following table summarizes interest expense for the periods indicated:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Credit Facility | $ | 10,771 | $ | 12,973 | |||||||
| 8.000% Senior Secured Notes due 2025 | 2,908 | 6,185 | |||||||||
| 5.375% Senior Notes due 2026 | 15,556 | 17,884 | |||||||||
| 6.875% Senior Notes due 2027 | 24,500 | 28,368 | |||||||||
| 3.250% Convertible Senior Notes due 2028 | 4,315 | — | |||||||||
| Amortization of debt issuance costs and debt discount | 4,992 | 5,923 | |||||||||
| Interest capitalized | (1,754) | (2,141) | |||||||||
| Total | $ | 61,288 | $ | 69,192 | |||||||
Interest expense was $7.9 million lower for the year ended December 31, 2021 compared to the year ended December 31, 2020 mainly due to (i) $6.2 million in lower interest incurred on our Senior Unsecured Notes during 2021, as $110.6 million of the senior notes due 2026 and $143.7 million of the senior notes due 2027 were extinguished in our debt exchange transaction in
47
May 2020; (ii) $3.3 million in decreased interest expense on our Senior Secured Notes due 2025 that were redeemed in their entirety in April of 2021; and (iii) $2.2 million in lower interest expense incurred on our credit facility due to fewer borrowings outstanding during 2021. These decreases were partially offset by $4.3 million in interest incurred on our Convertible Senior Notes that were issued in March of 2021. Refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information on our senior notes and debt transactions.
Our weighted average borrowings outstanding under our credit facility were $265.8 million during 2021 compared to $334.2 million in 2020. Our credit facility’s weighted average effective interest rate (which is a LIBOR-based rate) remained consistent at 3.3% for the years ended December 31, 2021 and 2020.
Gain (loss) on extinguishment of debt. During the year ended December 31, 2021, we redeemed at par all of our $127.1 million aggregate principal amount of Senior Secured Notes outstanding. In connection with this redemption, we incurred a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and debt discounts associated with these notes.
A gain of $143.4 million was recognized for the year ended December 31, 2020 related to our 2020 debt exchange transaction. This gain was determined based on the difference between the carrying value of the Senior Unsecured Notes extinguished less the fair value of our newly issued Senior Secured Notes on their date of issuance. Refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report for additional information regarding the debt extinguishment transactions discussed above.
Net Gain (Loss) on Derivative Instruments. Net gains and losses are a function of (i) changes in derivative fair values associated with fluctuations in the forward price curves for the commodities underlying each of our hedge contracts outstanding and (ii) monthly cash settlements on any closed out hedge positions during the period.
The following table presents gains and losses on our derivative instruments for the periods indicated:
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Realized cash settlement gains (losses) | $ | (132,125) | $ | (46,651) | |||||||
| Non-cash mark-to-market derivative gain (loss) | (16,700) | (17,884) | |||||||||
| Total | $ | (148,825) | $ | (64,535) | |||||||
Income Tax (Expense) Benefit: The following table summarizes our pre-tax income (loss) and income tax (expense) benefit for the periods indicated.
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Income (loss) before income taxes | $ | 138,744 | $ | (770,323) | |||||||
| Income tax (expense) benefit | (569) | 85,124 | |||||||||
Our provision for income taxes for the years ended December 31, 2021 and 2020 differs from the amounts that would be provided by applying the statutory U.S. federal income tax rate of 21% to pre-tax book income (loss) primarily due to (i) permanent differences; (ii) state income taxes; and (iii) any changes during the period in our deferred tax asset valuation allowance.
For the year ended December 31, 2020, we recognized a deferred tax asset valuation allowance (“Valuation Allowance”) of $77.0 million against net operating losses generated during the period, which were estimated as unlikely to be realized in future periods. During the year ended December 31, 2021, we reduced our Valuation Allowance to $40.1 million as a result of net income generated during the year. These changes in our Valuation Allowance during each respective year are the primary factor reducing our income tax expense to $0.6 million and benefit to $85.1 million from the income tax expense or benefit that would otherwise be due based on U.S. statutory rates, for the years ended December 31, 2021 and December 31, 2020, respectively.
For the Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019
Refer to Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations in the 2020 Annual Report on Form 10-K filed with the SEC for a discussion of the results of operations for the year ended December 31, 2020 compared to the year ended December 31, 2019.
48
Liquidity and Capital Resources
Overview
Our drilling and completion activities require us to make significant capital expenditures. Historically, our primary sources of liquidity have been cash flows from operations, borrowings under CRP’s revolving credit facility, proceeds from offerings of debt or equity securities, or proceeds from the sale of oil and gas properties. Future cash flows are subject to a number of variables, including oil and natural gas prices, which have been and will likely continue to be volatile. Lower commodity prices can negatively impact our cash flows and our ability to access debt or equity markets, and sustained low oil and natural gas prices could have a material and adverse effect on our liquidity position. To date, our primary use of capital has been for drilling and development capital expenditures and for the acquisition of oil and natural gas properties. The following table summarizes our capital expenditures (“capex”) incurred during the year:
| (in millions) | Year Ended December 31, 2021 | ||||
| Drilling, completion and facilities | $ | 313.0 | |||
| Infrastructure, land and other | 8.5 | ||||
| Total capital expenditures incurred | $ | 321.5 | |||
We continually evaluate our capital needs and compare them to our capital resources. We operated a two-rig drilling program for the year ended December 31, 2021, and we plan to operate two rigs throughout 2022. We expect our total capex budget for 2022 to be between $365 million to $425 million, of which $350 million to $400 million is allocated to drilling, completion and facilities activity. We funded our capital expenditures for 2021 entirely from cash flows from operations, and we expect to fund our 2022 capex budget entirely from cash flows from operations given our anticipated level of oil and gas production, current commodity prices and our commodity hedge positions in place. We were free cash flow positive during the year ended December 31, 2021 such that (notwithstanding our debt refinancing transactions discussed below and net proceeds received from oil and gas property sales) we were still able to pay down material borrowings under our credit agreement during the period. Based upon current commodity prices, we expect to continue to pay down borrowings next year from our expected free cash flow generation in 2022, and in addition, we may, from time to time, seek to retire or purchase our outstanding senior notes through cash purchases and/or exchanges for debt or equity in open-market purchases, privately negotiated transactions or otherwise.
In February 2022, our Board of Directors authorized a Repurchase Program to acquire up to $350 million of our outstanding Common Stock. We intend to use the program to reduce our shares of Common Stock outstanding and plan to fund these share repurchases with cash on hand and cash flow from operations. Such repurchases or exchanges would be made at terms and prices determined by us based upon prevailing market conditions, applicable legal requirements, available liquidity, compliance with our debt and other agreements and other factors.
Because we are the operator of a high percentage of our acreage, we can control the amount and timing of our capital expenditures. We can choose to defer or accelerate a portion of our planned capex depending on a variety of factors, including but not limited to: prevailing and anticipated prices for crude oil and natural gas; oil storage or transportation constraints; the success of our drilling activities; the availability of necessary equipment, infrastructure and capital; the receipt and timing of required regulatory permits and approvals; seasonal conditions; property or land acquisition costs; and the level of participation by other working interest owners.
We cannot ensure that cash flows from operations will be available or other sources of needed capital on acceptable terms, or at all. Further, our ability to access the public or private debt or equity capital markets at economic terms in the future will be affected by general economic conditions, the domestic and global oil and financial markets, our operational and financial performance, the value and performance of our debt or equity securities, prevailing commodity prices and other macroeconomic factors outside of our control.
Moreover, to manage our future maturities, lower interest expense, and improve our liquidity position, we issued 3.25% Convertible Senior Notes in March 2021, which resulted in net proceeds of $163.6 million. The proceeds were used to repay borrowing outstanding under CRP’s revolving credit facility and to fund the cost of entering into capped call spread transactions of $14.7 million. In April 2021, we redeemed at par all of our 2025 senior secured notes ($127.1 million) that bore interest at 8% per year and paid accrued interest of $3.8 million on these notes, which was the intended use of proceeds from the Convertible Senior Notes offering. As a result of this refinancing transaction, we were also able to reduce net borrowings outstanding under CRP’s revolving credit facility by approximately $20 million.
49
Analysis of Cash Flow Changes
The following table summarizes our cash flows for the periods indicated:
| Year Ended December 31, | |||||||||||||||||
(in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
Net cash provided by operating activities | $ | 525,619 | $ | 171,376 | $ | 564,173 | |||||||||||
Net cash used in investing activities | (226,476) | (326,323) | (932,989) | ||||||||||||||
Net cash (used in) provided by financing activities | (297,547) | 147,743 | 362,937 | ||||||||||||||
Cash Flows from 2021 Compared to 2020. For the year ended December 31, 2021, we generated $525.6 million of cash from operating activities, an increase of $354.2 million from 2020. Cash provided by operating activities increased primarily due to higher realized prices for all commodities, lower exploration and other expense, cash interest payments, lease operating expenses, and the timing of vendor payments during 2021 as compared to 2020. These increasing factors were partially offset by lower production volumes, higher GP&T and severance and ad valorem costs, the timing of our receivable collections, and cash settlement losses from derivatives for the year ended December 31, 2021 as compared to the same 2020 period. Refer to Results of Operations for more information on the impact of volumes and prices on revenues and on fluctuations in our operating expenses between periods.
For the year ended December 31, 2021, cash flows from operating activities, proceeds from the sale of oil and natural gas properties and net proceeds from the issuance of the Convertible Senior Notes were used to finance $319.6 million of drilling and development cash expenditures, repay net borrowings of $305 million under our credit facility, redeem $127.1 million of our 2025 senior secured notes outstanding and to fund $14.7 million in capped call transactions.
Cash Flows from 2020 Compared to 2019. For the year ended December 31, 2020, we generated $171.4 million of cash from operating activities, a decrease of $392.8 million from 2019. Cash provided by operating activities decreased primarily due to lower realized prices for oil and NGLs, lower production volumes for crude oil, residue gas and NGLs, higher exploration and other expenses, interest payments, cash settlement losses on derivatives, and the timing of vendor payments during 2020 as compared to 2019. These declining factors were partially offset by higher realized natural gas prices, lower lease operating expenses, production taxes, GP&T costs, cash G&A expenses, and the timing of our receivable collections during 2020 as compared to the same 2019 period.
For the year ended December 31, 2020, cash flows from operating activities, cash on hand, and net borrowings of $155.0 million under our credit facility were used to finance $318.5 million of drilling and development cash expenditures, to fund $8.5 million in oil and gas property acquisitions, and to finance $6.7 million of debt issuance and exchange costs.
Credit Agreement
CRP, our consolidated subsidiary, had a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). As of December 31, 2021, we had $25.0 million in borrowings outstanding and $669.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit.
On February 18, 2022, CRP entered into an amended and restated credit agreement (the “Amended Credit Agreement”) with a syndicate of banks replacing our previous Credit Agreement. The Amended Credit Agreement increased our elected commitments to $750 million, increased our borrowing base to $1.15 billion and extended the maturity of the credit facility to February 2027. Additionally, the Amended Credit Agreement provides for, among other things, the ability to repurchase outstanding common stock and junior debt, subject to certain leverage and elected commitment availability conditions and subject to the requirement that such repurchases are funded from our free cash flow. The Amended Credit Agreement also reflected a replacement of all provisions and related definitions regarding LIBOR with the Secured Overnight Financing Rate (“SOFR”).
The amount available to be borrowed under the Amended Credit Agreement is redetermined semi-annually each April 1 and October 1 by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations in between the scheduled redeterminations. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from those reserves, and our commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings outstanding exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Amended Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company.
Borrowings under the Amended Credit Agreement may be base rate loans or SOFR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for SOFR loans. SOFR loans bear interest at SOFR plus an applicable margin ranging from 225 to 325 basis points, depending on the percentage of elected commitments utilized, plus an additional 10 basis point credit spread adjustment. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted Term SOFR rate for a one-
50
month interest period plus 100 basis points, plus an applicable margin, ranging from 125 to 225 basis points, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused elected commitment amounts under its facility.
The Amended Credit Agreement contains restrictive covenants that limit our ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make restricted payments; (v) repurchase or redeem junior debt; (vi) enter into commodity hedges exceeding a specified percentage of our expected production; (vii) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (viii) incur liens; (ix) sell assets; and (x) engage in transactions with affiliates.
The Amended Credit Agreement also requires it to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including an add back of unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding the current portion of long-term debt under the Amended Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0; and
(ii) a leverage ratio, as defined within the Amended Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the prior four fiscal quarters, of not greater than 3.5 to 1.0.
CRP was in compliance with the covenants and financial ratios under the Amended Credit Agreement described above through the filing of this Annual Report.
Convertible Senior Notes
On March 19, 2021, CRP issued $150.0 million in aggregate principal amount of Convertible Senior Notes. On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional notes. The Convertible Senior Notes bear interest at an annual rate of 3.25% and are due on April 1, 2028. Interest is payable semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2021. The Convertible Senior Notes can be converted by noteholders prior to their maturity date upon the occurrence of certain events. CRP can settle the Convertible Senior Notes by paying or delivering cash, shares of our Common Stock, or a combination of cash and Common Stock, at CRP’s election.
The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s outstanding Senior Unsecured Notes as defined below.
In connection with the Convertible Senior Note issuance, CRP entered into privately negotiated capped call spread transactions (the “Capped Call Transactions”), that are expected to reduce potential dilution to the Common Stock upon a conversion and/or offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock (each subject to certain customary adjustments per the agreements).
Senior Notes
On November 30, 2017, CRP issued $400.0 million of 5.375% senior notes due 2026 (the “2026 Senior Notes”) and on March 15, 2019, CRP issued $500.0 million of 6.875% senior notes due 2027 (the “2027 Senior Notes” and, together with the 2026 Senior Notes, the “Senior Unsecured Notes”) in 144A private placements. In May 2020, $110.6 million aggregate principal amount of the 2026 Senior Notes and $143.7 million aggregate principal amount of the 2027 Senior Notes were validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount of 8.00% second lien senior secured notes due (the “Senior Secured Notes”). The Senior Secured Notes were fully redeemed at par in connection with the Convertible Senior Notes issuance during the second quarter of 2021.
The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by Centennial and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
The indentures governing the Senior Unsecured Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of December 31, 2021 and through the filing of this Annual Report.
For further information on our Convertible Senior Notes and Senior Unsecured Notes, refer to Note 4—Long-Term Debt under Part II, Item 8 of this Annual Report.
51
Obligations and Commitments
We routinely enter into or extend operating and transportation agreements, office and equipment leases, drilling rig contracts, among others, in the ordinary course of business. The following table summarizes our obligations and commitments as of December 31, 2021 to make future payments under long-term contracts for the time periods specified below.
| (in thousands) | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | ||||||||||||||||||||||||||||||||||
Operating leases(1) | $ | 1,603 | $ | 2,395 | $ | 2,452 | $ | 2,522 | $ | 2,341 | $ | 10,691 | $ | 22,004 | |||||||||||||||||||||||||||
Purchase obligations(2) | 5,157 | 5,192 | 5,206 | 5,192 | 5,192 | — | 25,939 | ||||||||||||||||||||||||||||||||||
Asset retirement obligations(3) | 229 | — | 490 | — | — | 16,521 | 17,240 | ||||||||||||||||||||||||||||||||||
Long term debt obligations(4) | — | 25,000 | — | — | 289,448 | 526,351 | 840,799 | ||||||||||||||||||||||||||||||||||
Cash interest expense on long-term debt obligations(5) | 48,841 | 46,689 | 45,582 | 45,582 | 30,672 | 13,114 | 230,480 | ||||||||||||||||||||||||||||||||||
Transportation agreements(6) | 2,989 | — | — | — | — | — | 2,989 | ||||||||||||||||||||||||||||||||||
Cash based compensation awards(7) | 859 | 50,366 | — | — | — | — | 51,225 | ||||||||||||||||||||||||||||||||||
| Total | $ | 59,678 | $ | 129,642 | $ | 53,730 | $ | 53,296 | $ | 327,653 | $ | 566,677 | $ | 1,190,676 | |||||||||||||||||||||||||||
(1) Operating leases consist of our office rental agreements and other wellhead equipment. Please refer to Note 15—Leases under Part II, Item 8 of this Annual Report for details on our operating lease commitments.
(2) Consists of an energy purchase agreement to buy a minimum amount of electricity at a fixed price or pay for underutilization. The obligations reported above represent our remaining minimum financial commitments pursuant to the terms of this contract as of December 31, 2021, however actual expenditures may exceed the minimum commitments presented above.
(3) Asset retirement obligations reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells and the related land restoration in accordance with applicable laws and regulations.
(4) Long-term debt consists of the principal amounts of our senior notes due and borrowings outstanding under the Credit Agreement as of December 31, 2021.
(5) Cash interest expense on our senior notes is estimated assuming no principal repayment until the maturity of the instruments. Cash interest expense on the Credit Agreement includes unused commitment fees and assumes no additional principal borrowings, repayments or changes to commitments under the agreement through the instrument due date.
(6) Transportation agreements include various firm natural gas transportation contracts whereby we are required to pay fixed pipeline capacity reservation fees over the contractual terms. The obligations reported above represent minimum financial commitments pursuant to the terms of these contracts. However, our expenditures under these contracts are likely to exceed the minimum commitments presented above.
(7) Consists of compensation based awards that are settable in cash including 5.5 million performance stock units. The obligation reported above for these performance stock units is based upon their estimated fair value as of December 31, 2021. However, these awards are subject to market-based vesting criteria with a payout ranging from 0% to 200% of the target number of units. Refer to Note 6—Stock-Based Compensation in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for more information.
Recently Issued Accounting Standards
Please refer to Note 1—Basis of Presentation and Summary of Significant Accounting Policies, in Part II, Item 8. Financial Statements and Supplementary Data in this Annual Report for a discussion of recently issued accounting standards and their anticipated effect on our business.
Critical Accounting Policies and Estimates
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of these statements requires us to make certain assumptions, judgments and estimates that affect the reported amounts of assets, liabilities, revenues and expenses, as well as, the disclosure of contingent assets, contingent liabilities and commitments as of the date of our financial statements. We base our assumptions and estimates on historical experience and other sources that we believe to be reasonable at the time. Actual results may vary from our estimates due to changes in circumstances, weather, politics, global economics, commodity prices, production performance, drilling results, mechanical problems, general business conditions and other factors. A summary of our significant accounting policies can be found in Note 1—Basis of Presentation and Summary of Significant Accounting Policies, Item 8. Financial Statements and Supplementary Data in this Annual Report.
We have outlined certain of our accounting policies below which require the application of significant judgment by our management.
52
Oil and Natural Gas Reserve Quantities
We use the successful efforts method of accounting for our oil and gas producing activities. The successful efforts method inherently relies on the estimation of proved crude oil, natural gas and NGL reserves. Reserve quantities and the related estimates of future net cash flows are used as inputs to our calculation of depletion, evaluation of proved properties for impairment, assessment of the expected realizability of our deferred income tax assets, and the standardized measure of discounted future net cash flows computations.
The process of estimating quantities of proved reserves is inherently imprecise and relies on the following: i) interpretations and judgment of available geological, geophysical, engineering and production data; ii) certain economic assumptions, some of which are mandated by the SEC, such as commodity prices; and iii) assumptions and estimates of underlying inputs such as operating expenses, capital expenditures, plug and abandonment costs and taxes. All of these assumptions may differ substantially from actual results, which could result in a significant change in our estimated quantities of proved reserves and their future net cash flows. We continually make revisions to reserve estimates throughout the year as additional information becomes available, and we make changes to depletion rates in the same reporting period that changes to reserve estimates are made.
Impairment of Oil and Natural Gas Properties
We assess our proved properties for impairment when events or changes in circumstances indicate that the carrying value of such proved property assets may not be recoverable. For purposes of an impairment evaluation, our proved oil and natural gas properties must be grouped at the lowest level for which independent cash flows can be identified. If the sum of the undiscounted estimated cash flows from the use of the asset group and its eventual disposition is less than the carrying value of an asset group, the carrying value is written down to its estimated fair value. Fair value for the purpose of measuring impairment write-downs are calculated using the present value of expected future cash flows that are estimated to be generated from the asset group. Fair value estimates are based on projected financial information which we believe to be reasonably likely to occur, as of the date that the impairment write-down is being measured. However, such future cash flow estimates are based on numerous assumptions that can materially affect our estimates, and such assumptions are subject to change with variations in commodity prices, production performance, drilling results, operating and development costs, underlying oil and gas reserve quantities, and other internal or external factors.
Unproved properties consist of the costs we incurred to acquire undeveloped leasehold acreage as well as the costs we incurred to acquire unproved reserves. Unproved properties with individually significant acquisition costs are periodically assessed for impairment based on remaining lease term, drilling results, reservoir performance, seismic interpretation or changes in future plans to develop acreage. Unproved properties which are not individually significant are amortized by prospect, based on our historical experience, current drilling plan, existing geological data and average remaining lease terms. Changes in our assumptions as to the estimated nonproductive portion of our undeveloped leases could result in additional impairment charges.
53
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
The term “market risk” as it applies to our business refers to the risk of loss arising from adverse changes in oil and natural gas prices and interest rates, and we are exposed to market risk as described below. The primary objective of the following information is to provide quantitative and qualitative information about our potential exposure to market risks. The disclosures are not meant to be precise indicators of expected future losses, but rather indicators of reasonably possible losses. All of our market risk sensitive instruments were entered into for purposes other than speculative trading.
Commodity Price Risk
Our primary market risk exposure is in the pricing that we receive for our oil, natural gas and NGL production. Pricing for oil, natural gas and NGLs has been volatile and unpredictable for several years, and we expect this volatility to continue for the foreseeable future. Based on our production for the year ended December 31, 2021, our oil and gas sales for the year ended December 31, 2021 would have moved up or down $74.3 million for each 10% change in oil prices per Bbl, $13.7 million for each 10% change in NGL prices per Bbl, and $14.9 million for each 10% change in natural gas prices per Mcf.
Due to this volatility, we have historically used and will continue to selectively use, commodity derivative instruments (such as collars, swaps and basis swaps) to mitigate the price risk associated with a portion of our anticipated production. Our derivative instruments allow us to reduce, but not eliminate, the variability in cash flows that can emanate from fluctuations in oil and natural gas prices, and they thereby provide increased certainty of cash flows for our drilling program and debt service requirements. These instruments provide only partial price protection against declines in oil and natural gas prices, but alternatively they partially limit our potential gains from future increases in price. Our Amended Credit Agreement limits our ability to enter into commodity hedges covering greater than 85% of our reasonably anticipated, projected production from proved properties.
The table below summarizes the terms of the derivative contracts we had in place as of December 31, 2021 and additional contracts entered into through February 18, 2022. Refer to Note 7—Derivative Instruments under Part II, Item 8 of this Annual Report for open derivative positions as of December 31, 2021.
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
Crude oil swaps | January 2022 - March 2022 | 1,080,000 | 12,000 | $65.03 | |||||||||||||||||||
| April 2022 - June 2022 | 1,092,000 | 12,000 | 65.28 | ||||||||||||||||||||
| July 2022 - September 2022 | 782,000 | 8,500 | 65.46 | ||||||||||||||||||||
| October 2022 - December 2022 | 690,000 | 7,500 | 65.63 | ||||||||||||||||||||
| January 2023 - March 2023 | 225,000 | 2,500 | 73.51 | ||||||||||||||||||||
| April 2023 - June 2023 | 227,500 | 2,500 | 73.25 | ||||||||||||||||||||
| July 2023 - September 2023 | 92,000 | 1,000 | 72.98 | ||||||||||||||||||||
| October 2023 - December 2023 | 92,000 | 1,000 | 72.98 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||||||||
Crude oil collars | January 2022 - March 2022 | 225,000 | 2,500 | $ | 63.60 | - | $ | 74.30 | |||||||||||||||||||||
| April 2022 - June 2022 | 227,500 | 2,500 | 63.20 | - | 72.41 | ||||||||||||||||||||||||
| July 2022 - September 2022 | 184,000 | 2,000 | 75.00 | - | 89.05 | ||||||||||||||||||||||||
| October 2022 - December 2022 | 184,000 | 2,000 | 75.00 | - | 89.05 | ||||||||||||||||||||||||
| January 2023 - March 2023 | 225,000 | 2,500 | 70.00 | - | 81.36 | ||||||||||||||||||||||||
| April 2023 - June 2023 | 227,500 | 2,500 | 70.00 | - | 81.36 | ||||||||||||||||||||||||
| July 2023 - September 2023 | 138,000 | 1,500 | 70.00 | - | 80.17 | ||||||||||||||||||||||||
| October 2023 - December 2023 | 138,000 | 1,500 | 70.00 | - | 80.17 | ||||||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
Crude oil basis differential swaps | January 2022 - March 2022 | 538,500 | 5,983 | $0.29 | |||||||||||||||||||
| April 2022 - June 2022 | 591,500 | 6,500 | 0.32 | ||||||||||||||||||||
| July 2022 - September 2022 | 552,000 | 6,000 | 0.29 | ||||||||||||||||||||
| October 2022 - December 2022 | 552,000 | 6,000 | 0.29 | ||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
Crude oil roll differential swaps | January 2022 - March 2022 | 900,000 | 10,000 | $0.71 | |||||||||||||||||||
| April 2022 - June 2022 | 910,000 | 10,000 | 0.71 | ||||||||||||||||||||
| July 2022 - September 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
| October 2022 - December 2022 | 920,000 | 10,000 | 0.71 | ||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
Natural gas swaps | January 2022 - March 2022 | 2,700,000 | 30,000 | $3.00 | |||||||||||||||||||
| April 2022 - June 2022 | 2,730,000 | 30,000 | 3.24 | ||||||||||||||||||||
| July 2022 - September 2022 | 2,760,000 | 30,000 | 3.24 | ||||||||||||||||||||
| October 2022 - December 2022 | 1,540,000 | 16,739 | 3.15 | ||||||||||||||||||||
54
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(2) | ||||||||||||||||||||||||||
Natural gas collars | January 2022 - March 2022 | 1,800,000 | 20,000 | $ | 3.15 | - | $ | 4.65 | |||||||||||||||||||||
| April 2022 - June 2022 | 1,820,000 | 20,000 | 3.50 | - | 3.97 | ||||||||||||||||||||||||
| July 2022 - September 2022 | 1,840,000 | 20,000 | 3.50 | - | 3.97 | ||||||||||||||||||||||||
| October 2022 - December 2022 | 2,450,000 | 26,630 | 3.87 | - | 5.06 | ||||||||||||||||||||||||
| January 2023 - March 2023 | 2,700,000 | 30,000 | 4.00 | - | 5.42 | ||||||||||||||||||||||||
| April 2023 - June 2023 | 910,000 | 10,000 | 3.00 | - | 4.09 | ||||||||||||||||||||||||
| July 2023 - September 2023 | 920,000 | 10,000 | 3.00 | - | 4.09 | ||||||||||||||||||||||||
| October 2023 - December 2023 | 920,000 | 10,000 | 3.17 | - | 4.74 | ||||||||||||||||||||||||
| January 2024 - March 2024 | 910,000 | 10,000 | 3.25 | - | 5.06 | ||||||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas basis differential swaps | January 2022 - March 2022 | 4,500,000 | 50,000 | $(0.29) | |||||||||||||||||||
| April 2022 - June 2022 | 1,820,000 | 20,000 | (0.45) | ||||||||||||||||||||
| July 2022 - September 2022 | 1,840,000 | 20,000 | (0.45) | ||||||||||||||||||||
| October 2022 - December 2022 | 1,840,000 | 20,000 | (0.45) | ||||||||||||||||||||
| January 2023 - March 2023 | 1,350,000 | 15,000 | (0.85) | ||||||||||||||||||||
| April 2023 - June 2023 | 1,365,000 | 15,000 | (0.85) | ||||||||||||||||||||
| July 2023 - September 2023 | 1,380,000 | 15,000 | (0.85) | ||||||||||||||||||||
| October 2023 - December 2023 | 1,380,000 | 15,000 | (0.85) | ||||||||||||||||||||
(1) These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These natural gas basis swap contracts are settled based on the difference between the inside FERC’s West Texas WAHA price and the NYMEX price of natural gas, during each applicable monthly settlement period.
Changes in the fair value of derivative contracts from December 31, 2020 to December 31, 2021, are presented below:
| (in thousands) | Commodity derivative asset (liability) | |||||||
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2020 | $ | (18,209) | ||||||
| Commodity hedge contract settlement payments, net of any receipts | 132,125 | |||||||
Cash and non-cash mark-to-market losses on commodity hedge contracts(1) | (148,826) | |||||||
| Net fair value of oil and gas derivative contracts outstanding as of December 31, 2021 | $ | (34,910) | ||||||
(1) At inception, new derivative contracts entered into by us have no intrinsic value.
A hypothetical upward or downward shift of 10% per Bbl in the NYMEX forward curve for crude oil as of December 31, 2021 would cause a $29.4 million increase or $29.0 million decrease, respectively, in this fair value position, and a hypothetical upward or downward shift of 10% per Mcf in the NYMEX forward curve for natural gas as of December 31, 2021 would cause a $3.5 million increase or $3.4 million decrease, respectively, in this same fair value position.
Interest Rate Risk
Our ability to borrow and the rates offered by lenders can be adversely affected by deteriorations in the credit markets and/or downgrades in our credit rating. CRP’s Amended Credit Agreement interest rate is based on a SOFR spread, which exposes us to interest rate risk to the extent we have borrowings outstanding under this credit facility.
At December 31, 2021, we had $25.0 million of debt outstanding under our previous credit facility, with a weighted average interest rate of 3.00%. Assuming no change in the amount outstanding, the impact on interest expense of a 1.0% increase or decrease in the weighted average interest rate would have been approximately $0.3 million per year. We do not
55
currently have or intend to enter into any derivative hedge contracts to protect against fluctuations in interest rates that are applicable to our outstanding indebtedness.
The remaining long-term debt principal balance of $815.8 million consists of our senior notes, which have fixed interest rates; therefore, interest payments that come due on this indebtedness are not affected by interest rate movements. For additional information regarding our debt instruments, see Note 4—Long-Term Debt, in Item 8. Financial Statements and Supplementary Data in this Annual Report.
56
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
CENTENNIAL RESOURCE DEVELOPMENT, INC.
INDEX TO FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
| Page | |||||
| Supplemental Information to Consolidated Financial Statements | |||||
57
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Centennial Resource Development, Inc.:
Opinion on the Consolidated Financial Statements
We have audited the accompanying consolidated balance sheets of Centennial Resource Development, Inc. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.
Basis for Opinion
These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matter
The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
Estimation of oil and gas reserves on depletion expense related to proved oil and gas properties
As discussed in Note 1 to the consolidated financial statements, capitalized proved property acquisition and development costs are depleted on a units-of-production method, which is based on the estimated oil and gas reserves remaining. For the year ended December 31, 2021, the Company recorded depletion expense of proved oil and gas properties included in total depreciation, depletion and amortization expense of $289.1 million. The estimation of economically recoverable proved oil and gas reserves requires the expertise of professional petroleum reserve engineers who take into consideration forecasted production, operating and development cost assumptions and forecasted oil and gas prices inclusive of market differentials. The Company annually engages independent reserve engineers to estimate the proved oil and gas reserves and the Company’s internal reserve engineers update the estimates of proved oil and gas reserves on a quarterly basis.
We identified the estimation of oil and gas reserves on depletion expense related to proved oil and gas properties as a critical audit matter. There was a high degree of subjectivity in evaluating the estimate of proved oil and gas reserves, which is a significant input into the calculation of depletion. Subjective auditor judgment was required to evaluate the
58
assumptions used by the Company related to forecasted production, operating and development costs, and forecasted oil and gas prices inclusive of market differentials.
The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the Company’s process to estimate depletion expense related to proved oil and gas properties. This included controls related to the assumptions used in the proved oil and gas reserves estimate, and to calculate depletion expense. We evaluated (1) the professional qualifications of the Company’s internal reserve engineers as well as the external reserve engineers and external engineering firm, (2) the knowledge, skills, and ability of the Company’s internal and external reserve engineers, and (3) the relationship of the external reserve engineers and external engineering firm to the Company. We assessed the methodology used by the Company to estimate the reserves for consistency with industry and regulatory standards. We assessed the data used in the average of the first-day-of-the-month pricing assumptions used in the internal reserve engineers’, and the independent reserve engineers’ estimates of the proved reserves, by comparing them to publicly available oil and gas benchmark pricing data, calculations of historical differentials and existing contractual arrangements. We evaluated assumptions used in the internal reserve engineers’ and independent reserve engineers’ estimates regarding future operating and development costs by comparing them to historical information including assessing the nature and timing of future development costs compared to development plan. Additionally, we compared the forecasted production volumes to historical production, and we compared the Company’s historical production forecasts to actual production volumes to assess the Company’s ability to accurately forecast. We read the report of the Company’s independent reserve engineers in order to understand the methods and assumptions used by the independent reserve engineers in connection with our evaluation of the Company’s reserve estimates. We compared reserve quantity information to the corresponding information used for depletion expense and recalculated the depletion expense for compliance with regulatory standards.
/s/ KPMG LLP
We have served as the Company’s auditor since 2014.
Denver, Colorado
February 24, 2022
59
Report of Independent Registered Public Accounting Firm
To the Shareholders and Board of Directors
Centennial Resource Development, Inc.:
Opinion on Internal Control Over Financial Reporting
We have audited Centennial Resource Development, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2022 expressed an unqualified opinion on those consolidated financial statements.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ KPMG LLP
Denver, Colorado
February 24, 2022
60
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED BALANCE SHEETS
(in thousands, except share and per share amounts)
| December 31, 2021 | December 31, 2020 | ||||||||||
| ASSETS | |||||||||||
| Current assets | |||||||||||
| Cash and cash equivalents | $ | $ | |||||||||
| Accounts receivable, net | |||||||||||
| Prepaid and other current assets | |||||||||||
| Total current assets | |||||||||||
Property and equipment | |||||||||||
| Oil and natural gas properties, successful efforts method | |||||||||||
| Unproved properties | |||||||||||
| Proved properties | |||||||||||
| Accumulated depreciation, depletion and amortization | ( | ( | |||||||||
| Total oil and natural gas properties, net | |||||||||||
| Other property and equipment, net | |||||||||||
| Total property and equipment, net | |||||||||||
| Noncurrent assets | |||||||||||
| Operating lease right-of-use assets | |||||||||||
| Other noncurrent assets | |||||||||||
| TOTAL ASSETS | $ | $ | |||||||||
| LIABILITIES AND EQUITY | |||||||||||
| Current liabilities | |||||||||||
| Accounts payable and accrued expenses | $ | $ | |||||||||
| Operating lease liabilities | |||||||||||
| Other current liabilities | |||||||||||
| Total current liabilities | |||||||||||
| Noncurrent liabilities | |||||||||||
| Long-term debt, net | |||||||||||
| Asset retirement obligations | |||||||||||
| Deferred income taxes | |||||||||||
| Operating lease liabilities | |||||||||||
| Other noncurrent liabilities | |||||||||||
| Total liabilities | |||||||||||
Commitments and contingencies (Note 13) | |||||||||||
| Shareholders’ equity | |||||||||||
Common stock, $ | |||||||||||
Class A: | |||||||||||
| Additional paid-in capital | |||||||||||
| Retained earnings (accumulated deficit) | ( | ( | |||||||||
| Total shareholders’ equity | |||||||||||
| Noncontrolling interest | |||||||||||
| Total equity | |||||||||||
| TOTAL LIABILITIES AND EQUITY | $ | $ | |||||||||
The accompanying notes are an integral part of these consolidated financial statements.
61
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF OPERATIONS
(in thousands, except per share data)
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Operating revenues | |||||||||||||||||
| Oil and gas sales | $ | $ | $ | ||||||||||||||
| Operating expenses | |||||||||||||||||
| Lease operating expenses | |||||||||||||||||
| Severance and ad valorem taxes | |||||||||||||||||
| Gathering, processing and transportation expenses | |||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||
| Impairment and abandonment expense | |||||||||||||||||
| Exploration and other expenses | |||||||||||||||||
| General and administrative expenses | |||||||||||||||||
| Total operating expenses | |||||||||||||||||
| Net gain (loss) on sale of long-lived assets | ( | ||||||||||||||||
| Proceeds from terminated sale of assets | |||||||||||||||||
| Income (loss) from operations | ( | ||||||||||||||||
| Other income (expense) | |||||||||||||||||
| Interest expense | ( | ( | ( | ||||||||||||||
| Gain (loss) on extinguishment of debt | ( | ||||||||||||||||
| Net gain (loss) on derivative instruments | ( | ( | ( | ||||||||||||||
| Other income (expense) | |||||||||||||||||
| Total other income (expense) | ( | ( | |||||||||||||||
| Income (loss) before income taxes | ( | ||||||||||||||||
| Income tax (expense) benefit | ( | ( | |||||||||||||||
| Net income (loss) | ( | ||||||||||||||||
| Less: Net (income) loss attributable to noncontrolling interest | ( | ||||||||||||||||
Net income (loss) attributable to Class A Common Stock | $ | $ | ( | $ | |||||||||||||
| Income (loss) per share of Class A Common Stock: | |||||||||||||||||
| Basic | $ | $ | ( | $ | |||||||||||||
| Diluted | $ | $ | ( | $ | |||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
62
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS
(in thousands)
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Cash flows from operating activities: | |||||||||||||||||
| Net income (loss) | $ | $ | ( | $ | |||||||||||||
| Adjustments to reconcile net income (loss) to net cash provided by operating activities: | |||||||||||||||||
| Depreciation, depletion and amortization | |||||||||||||||||
| Stock-based compensation expense - equity awards | |||||||||||||||||
| Stock-based compensation expense - liability awards | |||||||||||||||||
| Impairment and abandonment expense | |||||||||||||||||
| Exploratory dry hole costs | |||||||||||||||||
| Deferred tax expense (benefit) | ( | ||||||||||||||||
| Net (gain) loss on sale of long-lived assets | ( | ( | |||||||||||||||
| Non-cash portion of derivative (gain) loss | ( | ||||||||||||||||
| Amortization of debt issuance costs and debt discount | |||||||||||||||||
| (Gain) loss on extinguishment of debt | ( | ||||||||||||||||
| Changes in operating assets and liabilities: | |||||||||||||||||
| (Increase) decrease in accounts receivable | ( | ( | |||||||||||||||
| (Increase) decrease in prepaid and other assets | ( | ( | |||||||||||||||
| Increase (decrease) in accounts payable and other liabilities | ( | ||||||||||||||||
| Net cash provided by operating activities | |||||||||||||||||
| Cash flows from investing activities: | |||||||||||||||||
| Acquisition of oil and natural gas properties | ( | ( | ( | ||||||||||||||
| Drilling and development capital expenditures | ( | ( | ( | ||||||||||||||
| Purchases of other property and equipment | ( | ( | ( | ||||||||||||||
| Proceeds from sales of oil and natural gas properties | |||||||||||||||||
| Net cash used in investing activities | ( | ( | ( | ||||||||||||||
| Cash flows from financing activities: | |||||||||||||||||
| Proceeds from borrowings under revolving credit facility | |||||||||||||||||
| Repayment of borrowings under revolving credit facility | ( | ( | ( | ||||||||||||||
| Proceeds from issuance of senior notes | |||||||||||||||||
| Debt exchange and debt issuance costs | ( | ( | ( | ||||||||||||||
| Premiums paid on capped call transactions | ( | ||||||||||||||||
| Redemption of senior secured notes | ( | ||||||||||||||||
| Proceeds from exercise of stock options | |||||||||||||||||
| Restricted stock used for tax withholdings | ( | ( | ( | ||||||||||||||
| Net cash (used in) provided by financing activities | ( | ||||||||||||||||
| Net increase (decrease) in cash, cash equivalents and restricted cash | ( | ( | |||||||||||||||
| Cash, cash equivalents and restricted cash, beginning of period | |||||||||||||||||
| Cash, cash equivalents and restricted cash, end of period | $ | $ | $ | ||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
63
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF CASH FLOWS (Continued)
(in thousands)
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
Supplemental cash flow information | |||||||||||||||||
Cash paid for interest | $ | $ | $ | ||||||||||||||
Supplemental non-cash activity | |||||||||||||||||
Accrued capital expenditures included in accounts payable and accrued expenses | $ | $ | $ | ||||||||||||||
| Asset retirement obligations incurred, including revisions to estimates | ( | ||||||||||||||||
| Change in senior notes from debt exchange: | |||||||||||||||||
| Senior Secured Notes issued in the debt exchange, net of debt discount | |||||||||||||||||
| 2026 Senior Notes extinguished in the debt exchange, net of unamortized debt issue costs | ( | ||||||||||||||||
| 2027 Senior Notes extinguished in the debt exchange, net of unamortized discount and debt issue costs | ( | ||||||||||||||||
Reconciliation of cash, cash equivalents and restricted cash presented in the consolidated statements of cash flows:
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Cash and cash equivalents | $ | $ | $ | ||||||||||||||
Restricted cash(1) | |||||||||||||||||
| Total cash, cash equivalents and restricted cash | $ | $ | $ | ||||||||||||||
(1) Included in Prepaid and other current assets as of December 31, 2021 and in Prepaid and other current assets and Other noncurrent assets as of December 31, 2020 and 2019 in the consolidated balance sheets.
The accompanying notes are an integral part of these consolidated financial statements.
64
CENTENNIAL RESOURCE DEVELOPMENT, INC.
CONSOLIDATED STATEMENTS OF SHAREHOLDERS’ EQUITY
(in thousands)
| Common Stock | Additional Paid-In Capital | Retained Earnings (Accumulated Deficit) | Total Shareholder’s Equity | Non-controlling Interest | Total Equity | ||||||||||||||||||||||||||||||||||||||||||||||||
| Class A | Class C | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Shares | Amount | Shares | Amount | ||||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2018 | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock issued | — | — | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | ( | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock used for tax withholding | ( | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation - equity awards | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Conversion of common shares from Class C to Class A, net of tax | ( | ( | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2019 | |||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock issued | — | — | ( | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | ( | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock used for tax withholding | ( | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Class A common stock under Employee Stock Purchase Plan | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation - equity awards | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Conversion of common shares from Class C to Class A, net of tax | — | ( | — | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | ( | ( | ( | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2020 | ( | ||||||||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock issued | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock forfeited | ( | — | — | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||
| Restricted stock used for tax withholding | ( | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Issuance of Class A common stock under Employee Stock Purchase Plan | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Capped call premiums | — | — | — | — | ( | — | ( | — | ( | ||||||||||||||||||||||||||||||||||||||||||||
| Stock-based compensation - equity awards | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Stock option exercises | — | — | — | — | — | ||||||||||||||||||||||||||||||||||||||||||||||||
| Net income (loss) | — | — | — | — | — | — | |||||||||||||||||||||||||||||||||||||||||||||||
| Balance at December 31, 2021 | $ | $ | $ | $ | ( | $ | $ | $ | |||||||||||||||||||||||||||||||||||||||||||||
The accompanying notes are an integral part of these consolidated financial statements.
65
Note 1—Basis of Presentation and Summary of Significant Accounting Policies
Description of Business
Centennial Resource Development, Inc. is an independent oil and natural gas company focused on the development of crude oil and associated liquids-rich natural gas reserves in the Permian Basin. The Company’s assets are concentrated in the Delaware Basin, a sub-basin of the Permian Basin, and its properties consist of large, contiguous acreage blocks located in West Texas and New Mexico. Unless otherwise specified or the context otherwise requires, all references in these notes to “Centennial” or the “Company” are to Centennial Resource Development, Inc. and its consolidated subsidiary, Centennial Resource Production, LLC (“CRP”).
Principles of Consolidation and Basis of Presentation
The consolidated financial statements include the accounts of the Company, its subsidiary CRP and CRP’s wholly-owned subsidiaries and have been prepared in accordance with accounting principles generally accepted in the United States of America (“GAAP”) and the rules and regulations of the United States Securities and Exchange Commission (“SEC”). All intercompany balances and transactions have been eliminated in consolidation.
Noncontrolling interests represent third-party ownership in CRP and is presented as a component of equity. See Note 9—Shareholders' Equity and Noncontrolling Interest for discussion on noncontrolling interest.
Use of Estimates
The preparation of the Company’s consolidated financial statements requires the Company’s management to make various assumptions, judgments and estimates to determine the reported amounts of assets, liabilities, revenues and expenses, and the disclosures of commitments and contingencies. Changes in these assumptions, judgments, and estimates will occur as a result of the passage of time and the occurrence of future events, and accordingly, actual results could differ from amounts previously established. Additionally, the prices received for oil, natural gas and NGL production can heavily influence the Company’s assumptions, judgments and estimates and continued volatility of oil and gas prices could have a significant impact on the Company’s estimates.
Cash and Cash Equivalents and Restricted Cash
The Company considers all highly liquid instruments with an original maturity of three months or less at the time of issuance to be cash equivalents. The carrying value of cash and cash equivalents approximates fair value because of the short-term maturity of these investments. From time to time, the Company is required to maintain cash in separate accounts, the use of which is restricted by the terms of contracted arrangements. Such amounts are included in Prepaid and other current assets as of December 31, 2021 and in Prepaid and other current assets and Other noncurrent assets as of December 31, 2020 in the consolidated balance sheets.
Accounts Receivable
Accounts receivable consists mainly of receivables from oil and natural gas purchasers and from joint interest owners on properties the Company operates. For receivables from joint interest owners, the Company typically has the ability to withhold future revenue disbursements to recover non-payment of joint interest billings. Accordingly, the Company’s oil and natural gas receivables are generally collected, and the Company has minimal bad debts.
Although diversified among many companies, collectability is dependent upon the financial wherewithal of each individual company and is influenced by the general economic conditions of the industry. Receivables are not collateralized, and the Company therefore establishes an allowance for doubtful accounts equal to the portions of its accounts receivable for which collectability is not reasonably assured. The Company had $0.1
66
Credit Risk and Other Concentrations
Centennial is exposed to credit risk in the event of nonpayment by counterparties. The Company normally sells production to a relatively small number of customers, as is customary in its business. The table below summarizes the purchasers that accounted for 10% or more of the Company’s total net revenues for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| BP America | % | % | % | ||||||||||||||
| Shell Trading (US) Company | % | % | % | ||||||||||||||
| Eagleclaw Midstream Ventures, LLC | % | % | % | ||||||||||||||
| ExxonMobil Oil Corporation | % | % | % | ||||||||||||||
During these periods, no other purchaser accounted for 10% or more of the Company’s net revenues. The loss of any of the Company’s major purchasers could materially and adversely affect its revenues in the short-term. However, based on the demand for oil and natural gas and the availability of other purchasers, the Company believes that the loss of any major purchaser would not have a material adverse effect on its financial condition and results of operations because crude oil and natural gas are fungible products with well-established markets and numerous purchasers.
By using derivative instruments to economically hedge exposures to changes in commodity prices, the Company also exposes itself to credit risk. When the fair value of a derivative contract is positive, the counterparty owes the Company, which creates credit risk. The Company minimizes the credit risk in derivative instruments by: (i) limiting its exposure to any single counterparty; and (ii) only entering into hedging arrangements with counterparties that are also participants in CRP’s credit agreement, all of which have investment-grade credit ratings.
Oil and Natural Gas Properties
The Company’s oil and natural gas producing activities are accounted for using the successful efforts method of accounting. Under the successful efforts method, the costs incurred to acquire, drill, and complete development wells are capitalized to proved properties. Exploration costs, including personnel and other internal costs, geological and geophysical expenses and delay rentals for oil and gas leases, are charged to expense as incurred. Costs of drilling exploratory wells, on the other hand, are initially capitalized but are charged to expense if the well is determined to be unsuccessful. Costs to operate, repair and maintain wells and field equipment are expensed as incurred.
The Company capitalizes interest on expenditures made in connection with exploration and development projects that are not subject to current amortization. Interest is capitalized only for the period that activities are in process to bring the projects to their intended use. Capitalized interest cannot exceed interest expense for the period capitalized. The Company capitalized interest of $1.8 million, $2.1 million and $4.1 million during the years ended December 31, 2021, 2020 and 2019, respectively.
Proved Properties. Costs incurred to obtain access to proved reserves and to provide facilities for extracting, treating, gathering and storing oil, natural gas and NGLs are capitalized. All costs incurred to drill and equip successful exploratory wells, development wells, development-type stratigraphic test wells, extension wells and service wells, are capitalized. Capitalized proved property acquisition and development costs are depleted using a units-of production method based on the remaining life of proved and proved developed reserves, respectively.
Net carrying values of retired, sold or abandoned properties that constitute less than a complete unit of depreciable property are charged or credited, net of proceeds, to accumulated depreciation, depletion and amortization unless doing so significantly affects the unit-of-production amortization rate, in which case a gain or loss is recognized. Gains or losses from the disposal of complete units of depreciable property are recognized to the consolidated statements of operations.
The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that there could be a possible decline in the recoverability of the carrying amount of such property. The Company estimates the expected future cash flows of its oil and natural gas properties and compares these undiscounted cash flows to the carrying amount of the oil and natural gas properties to determine if the carrying amount is recoverable. If the carrying amount exceeds the estimated undiscounted future cash flows, the Company will write down the carrying amount of the oil and natural gas properties to fair value. The factors used to determine fair value include, but are not limited to, estimates of reserves, future commodity prices, future production estimates, estimated future capital and operating expenditures and discount rates, which are based on a weighted average cost of capital. For the year ended December 31, 2020, a non-cash impairment of $591.8 million for proved oil and natural gas properties was recorded as a result of depressed oil and natural gas commodity prices. There were no impairments
67
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
of proved oil and natural gas properties for the years ended December 31, 2021 and 2019. Refer to Note 8—Fair Value Measurements for additional information on the 2020 impairment charge.
Unproved Properties. Unproved properties consist of costs to acquire undeveloped leases as well as costs to acquire unproved reserves, and they are both capitalized as incurred. These consist of costs incurred in obtaining a mineral interest or a right in a property such as a lease, in addition to broker fees, recording fees and other similar costs related to acquiring properties. Leasehold costs are classified as unproved until proved reserves are discovered on or otherwise attributed to the property, at which time the related unproved property costs are transferred to proved oil and natural gas properties.
Other Property and Equipment
Other property and equipment includes office furniture and equipment, buildings, vehicles, computer hardware and software and is recorded at cost. These assets are depreciated using the straight-line method over their estimated useful lives which range from to twenty years . Equipment upgrades and improvements are capitalized while expenditures for maintenance and repairs are expensed as incurred. When other property and equipment is sold or retired, the capitalized costs and related accumulated depreciation are removed from the accounts and a gain or loss is recorded in the consolidated statements of operations as needed.
Derivative Financial Instruments
In order to mitigate its exposure to oil and natural gas price volatility, the Company may periodically use derivative instruments, such as swaps, costless collars, basis swaps, and other similar agreements. To the extent legal right of offset exists with a counterparty, the Company reports derivative assets and liabilities on a net basis.
68
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Income Taxes
Income taxes are recognized based on earnings reported for tax return purposes and provisions recorded for deferred income taxes. Deferred income tax assets and liabilities are recognized based on temporary differences resulting from: (i) net operating loss carryforwards for income tax purposes, and (ii) differences between the amounts recorded to the consolidated financial statements and the tax basis of assets and liabilities, as measured using enacted statutory tax rates in effect at the end of a period. The effect of a change in tax rates or tax laws is recognized in income during the period such changes are enacted. A valuation allowance for deferred tax assets is established when it is more likely than not that some portion of the benefit from deferred tax assets will not be realized.
Stock-Based Compensation
The Company’s stock-based compensation consists of equity grants of restricted stock, stock options, and performance stock units to employees and directors, an employee stock purchase plan which is available to eligible employees, and grants of restricted stock units and performance stock units that are settled in cash. The Company determines compensation expense related to all equity-based awards based on their estimated fair value, and such expense is recognized on a straight-line basis over the applicable service period of the award. For cash settled awards classified as liabilities, compensation expense is estimated based on the fair value of the awards as of the balance sheet date, and such expense is recognized ratably over the period in which the award is expected to be paid. See Note 6—Stock-Based Compensation for additional information regarding the Company’s stock-based compensation.
Earnings (Loss) Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to the Company’s Class A common stock (the “Common Stock”) by the weighted average shares of Common Stock outstanding during each period. Dilutive EPS is calculated by dividing adjusted net income available to Common Stock by the weighted average shares of diluted Common Stock outstanding, which includes the effect of potentially dilutive securities. See Note 10—Earnings Per Share for additional information regarding the Company’s computation of EPS.
Segment Reporting
The Company operates in only one industry segment which is the exploration and production of oil and natural gas. All of its operations are conducted in one geographic area of the United States. All revenues are derived from customers located in the United States.
Note 2—Property Divestitures
2021 Disposition
On December 1, 2021, the Company completed the sale of approximately 6,200 net leasehold acres for an unadjusted sales price of $101 million. The divested assets represent non-core acreage that was mostly undeveloped but also contained 20 producing wells located on the southernmost portion of the Company’s position in Reeves County, Texas. This divestiture represented the sale of an entire field, which resulted in a net gain on sale of $33.9 million. The Company used the net proceeds from the sale to repay a portion of its borrowings outstanding under its Credit Agreement.
69
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
2020 Disposition
On February 24, 2020, the Company entered into a purchase and sale agreement (the “Agreement”) to sell certain of its water disposal assets. On May 15, 2020, the Agreement was terminated after the transaction failed to close by the outside date set forth in the Agreement.
The purchaser deposited $10.0 million of cash in an escrow account (the “Deposit”) which, in the event of termination, was to be distributed to the Company or the purchaser in accordance with the remedy provisions of the Agreement. In May 2021, a settlement between the Company and the purchaser was reached resulting in a partial distribution of the deposit to Centennial, which was included net of associated legal fees in the consolidated statements of operations.
Note 3—Accounts Receivable, Accounts Payable and Accrued Expenses
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
| Accrued oil and gas sales receivable, net | $ | $ | |||||||||
| Joint interest billings, net | |||||||||||
| Other | |||||||||||
| Accounts receivable, net | $ | $ | |||||||||
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
| Accounts payable | $ | $ | |||||||||
| Accrued capital expenditures | |||||||||||
| Revenues payable | |||||||||||
| Accrued employee compensation and benefits | |||||||||||
| Accrued interest | |||||||||||
| Accrued derivative settlements payable | |||||||||||
| Accrued expenses and other | |||||||||||
| Accounts payable and accrued expenses | $ | $ | |||||||||
70
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 4—Long-Term Debt
(in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
Credit Facility due 2023 | $ | $ | |||||||||
| Senior Notes | |||||||||||
Unamortized debt issuance costs on Senior Notes | ( | ( | |||||||||
Unamortized debt discount | ( | ( | |||||||||
Senior Notes, net | |||||||||||
Total long-term debt, net | $ | $ | |||||||||
Credit Agreement
CRP, the Company’s consolidated subsidiary, has a credit agreement with a syndicate of banks that provides for a five-year secured revolving credit facility, maturing on May 4, 2023 (the “Credit Agreement”). As of December 31, 2021, the Company had $25.0 million in borrowings outstanding and $669.2 million in available borrowing capacity, which was net of $5.8 million in letters of credit outstanding. From May of 2020 until April of 2021, the borrowing base had been reduced by an availability blocker of $31.8 million tied to the Senior Secured Notes. However, this availability blocker was eliminated as a result of the Senior Secured Notes redemption defined and discussed below.
The amount available to be borrowed under the Credit Agreement is equal to the lesser of (i) the borrowing base, (ii) aggregate elected commitments, which was set at $700.0 million, or (iii) $1.5 billion. The borrowing base is redetermined semi-annually in the spring and fall by the lenders in their sole discretion. It also allows for two optional borrowing base redeterminations on January 1 and July 1. The borrowing base depends on, among other things, the quantities of CRP’s proved oil and natural gas reserves, estimated cash flows from these reserves, and the Company’s commodity hedge positions. Upon a redetermination of the borrowing base, if actual borrowings exceed the revised borrowing capacity, CRP could be required to immediately repay a portion of its debt outstanding. Borrowings under the Credit Agreement are guaranteed by certain of CRP’s subsidiaries and the Company. In February 2022, CRP entered into a new revolving credit facility that replaced the existing Credit Agreement; refer to Note 16—Subsequent events for additional information.
Borrowings under the Credit Agreement may be base rate loans or LIBOR loans. Interest is payable quarterly for base rate loans and at the end of the applicable interest period for LIBOR loans. LIBOR loans bear interest at LIBOR (adjusted for statutory reserve requirements and subject to 1 % floor) plus an applicable margin, which ranged from 200 to 300 basis points as of December 31, 2021, depending on the percentage of the borrowing base utilized. Base rate loans bear interest at a rate per annum equal to the greatest of: (i) the agent bank’s prime rate; (ii) the federal funds effective rate plus 50 basis points; or (iii) the adjusted LIBOR rate for a one-month interest period plus 100 basis points, plus an applicable margin, which ranged 100 to 200 basis points as of December 31, 2021, depending on the percentage of the borrowing base utilized. CRP also pays a commitment fee of 37.5 to 50 basis points on unused amounts under its facility.
CRP’s Credit Agreement contains restrictive covenants that limit its ability to, among other things: (i) incur additional indebtedness; (ii) make investments and loans; (iii) enter into mergers; (iv) make or declare dividends; (v) enter into commodity hedges exceeding a specified percentage of the Company’s expected production; (vi) enter into interest rate hedges exceeding a specified percentage of its outstanding indebtedness; (vii) incur liens; (viii) sell assets; and (ix) engage in transactions with affiliates.
CRP’s Credit Agreement also requires it to maintain compliance with the following financial ratios:
(i) a current ratio, which is the ratio of CRP’s consolidated current assets (including unused commitments under the revolving credit facility and excluding non-cash derivative assets and certain restricted cash) to its consolidated current liabilities (excluding any current portion of long-term debt due under the Credit Agreement and non-cash derivative liabilities), of not less than 1.0 to 1.0;
71
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(ii) a first lien leverage ratio, as defined within the Credit Agreement as the ratio of first lien debt to EBITDAX for the rolling four fiscal quarter period, which may not exceed 2.75 to 1.00 beginning with the quarter ending June 30, 2020 and extending through the quarter ending December 31, 2021, after which the maximum ratio shall decrease to 2.50 to 1.00 for each of the quarters ending in 2022; and
(iii) a leverage ratio, as also defined in the Credit Agreement as the ratio of total funded debt to consolidated EBITDAX for the rolling four fiscal quarter period. Pursuant to amendments to the credit facility, the leverage ratio was suspended until March 31, 2022, at which time, the ratio may not exceed 5.0 to 1.0, with such maximum ratio declining at a rate of 0.25 for each succeeding quarter until March 31, 2023 when the ratio is set at not greater than 4.0 to 1.0.
CRP was in compliance with the covenants and applicable financial ratios described above as of December 31, 2021.
Convertible Senior Notes
On March 19, 2021, CRP issued $150 million in aggregate principal amount of 3.25 % senior unsecured convertible notes due 2028 (the “Convertible Senior Notes”). On March 26, 2021, CRP issued an additional $20.0 million of Convertible Senior Notes pursuant to the exercise of the underwriters’ over-allotment option to purchase additional Convertible Senior Notes. These issuances resulted in aggregate net proceeds to CRP of $163.6 million, after deducting debt issuance costs of $6.4 million. Interest is payable on the Convertible Senior Notes semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2021.
The Convertible Senior Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries.
The Convertible Senior Notes will mature on April 1, 2028 unless earlier repurchased, redeemed or converted. Before January 3, 2028, noteholders have the right to convert their Convertible Senior Notes (i) upon the occurrence of certain events, (ii) if the Company’s share price exceeds 130 % of the conversion price for any 20 trading days during the last 30 consecutive trading days of a calendar quarter, after June 30, 2021, or (iii) if the trading price per $1,000 principal amount of the notes is less than 98 % of the Company’s share price multiplied by the conversion rate, for a 10 consecutive trading day period. In addition, after January 2, 2028, noteholders may convert their Convertible Senior Notes at any time at their election through the second scheduled trading day immediately before the April 1, 2028 maturity date.
CRP can settle conversions by paying or delivering, as applicable, cash, shares of Common Stock, or a combination of cash and shares of Common Stock, at CRP’s election. The initial conversion rate is 159.2610 shares of Common Stock per $1,000 principal amount of Convertible Senior Notes, which represents an initial conversion price of approximately $6.28 per share of Common Stock. The conversion rate and conversion price are subject to customary adjustments upon the occurrence of certain events (as defined in the indenture) which, in certain circumstances, will increase the conversion rate for a specified period of time. In the context of this issuance, we refer to the notes as convertible in accordance with ASC 470 - Debt. However, per the terms of the Convertible Senior Notes’ indenture, the Convertible Senior Notes were issued by CRP and are exchangeable into shares of Centennial Resource Development, Inc.’s Common Stock.
CRP has the option to redeem, in whole or in part, all of the Convertible Senior Notes at any time on or after April 7, 2025, at a redemption price equal to 100 % of the principal amount, plus accrued and unpaid interest to the date of redemption, but only if the last reported sale price per share of Common Stock exceeds 130 % of the conversion price (i) for any 20 trading days during the 30 consecutive trading days ending on the day immediately before the date CRP sends the related redemption notice; and (ii) also on the trading day immediately before the date CRP sends such notice.
If certain corporate events occur, including certain business combination transactions involving the Company or CRP or a stock de-listing with respect to the Common Stock, noteholders may require CRP to repurchase their Convertible Senior Notes at a cash repurchase price equal to the principal amount of the Convertible Senior Notes to be repurchased, plus accrued and unpaid interest to the repurchase date.
Upon an Event of Default (as defined in the indenture governing the Convertible Senior Notes), the trustee or the holders of at least 25 % of the aggregate principal amount of then outstanding Convertible Senior Notes may declare the Convertible Senior Notes immediately due and payable. In addition, a default resulting from certain events of bankruptcy or insolvency with respect to the Company, CRP or any of the subsidiary guarantors will automatically cause all outstanding Convertible Senior Notes to become due and payable.
At issuance, the Company recorded a liability equal to the face value the Convertible Senior Notes, net of unamortized debt issuance costs in the line item Long-term debt, net in the consolidated balance sheets. As of December 31, 2021, the net liability recorded related to the Convertible Senior Notes was $164.2 million.
72
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Capped Called Transactions
In connection with the issuance of the Convertible Senior Notes in March 2021, CRP entered into privately negotiated capped call spread transactions with option counterparties (the “Capped Call Transactions”). The Capped Call Transactions cover the aggregate number of shares of Common Stock that initially underlie the Convertible Senior Notes and are expected to (i) generally reduce potential dilution to the Common Stock upon a conversion of the Convertible Senior Notes, and/or (ii) offset any cash payments CRP is required to make in excess of the principal amount of the Convertible Senior Notes, subject to a cap. The Capped Call Transactions have an initial strike price of $6.28 per share of Common Stock and an initial capped price of $8.4525 per share of Common Stock, each of which are subject to certain customary adjustments upon the occurrence of certain corporate events, as defined in the capped call agreements.
The cost of the Capped Call Transactions was $14.7 million, which was funded from proceeds from the Convertible Senior Note issuance. The cost to purchase the Capped Call Transactions was recorded to additional paid-in capital in the consolidated balances sheets and will not be subject to remeasurement each reporting period.
Senior Unsecured Notes Debt Exchange
On May 22, 2020, CRP completed its private exchange of debt pursuant to which a $254.2 million aggregate principal amount of Senior Unsecured Notes (defined below) was validly tendered and exchanged by certain eligible bondholders for consideration consisting of $127.1 million aggregate principal amount (the “Debt Exchange”) of newly issued 8.00 % second lien senior secured notes due 2025 (the “Senior Secured Notes”). The Company’s Debt Exchange was accounted for as an extinguishment of debt in accordance with ASC 470-50, Modifications and Extinguishments. As a result, a gain on the exchange of debt of $143.4 million was recognized in the consolidated statement of operations during the second quarter of 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the new Senior Secured Notes issued, net of their associated debt discount of $21.0 million, which was based on the Senior Secured Notes’ estimated fair value on the exchange date.
Senior Secured Notes
In connection with the Debt Exchange, on May 22, 2020, the Company issued $127.1 million aggregate principal amount of Senior Secured Notes. The Senior Secured Notes were recorded at their fair value on the date of issuance equal to 83.44 % of par (a debt discount of $21.0 million) and net of their associated debt issuance costs of $4.2 million.
In April 2021, the Company redeemed at par all of its $127.1 million aggregate principal amount of Senior Secured Notes, which was the intended use of proceeds from the Convertible Senior Notes offering. The Company paid accrued interest of $3.8 million and recorded a loss on debt extinguishment of $22.2 million related to the write-off of all unamortized debt issuance costs and discount amounts associated with the Senior Secured Notes.
Senior Unsecured Notes
On March 15, 2019, CRP issued $500.0 million of 6.875 % senior unsecured notes due 2027 (the “2027 Senior Notes”) in a 144A private placement at a price equal to 99.235 % of par that resulted in net proceeds to CRP of $489.0 million, after deducting the original issuance discount of $3.8 million and debt issuance costs of $7.2 million. Interest is payable on the 2027 Senior Notes semi-annually in arrears on each April 1 and October 1, which commenced on October 1, 2019. In May 2020 in connection with the Debt Exchange, $143.7 million aggregate principal amount of the 2027 Senior Notes was exchanged for Senior Secured Notes. As of December 31, 2021, the remaining aggregate principal amount of 2027 Senior Notes outstanding was $356.4 million.
On November 30, 2017, CRP issued at par $400.0 million of 5.375 % senior unsecured notes due 2026 (the “2026 Senior Notes” and collectively with the 2027 Senior Notes, the “Senior Unsecured Notes”) in an 144A private placement that resulted in net proceeds to CRP of $391.0 million, after deducting $9.0 million in debt issuance costs. Interest is payable on the 2026 Senior Notes semi-annually in arrears on each January 15 and July 15, which commenced on July 15, 2018. In May 2020 in connection with the Debt Exchange, $110.6 million aggregate principal amount of the 2026 Senior Notes was exchanged for Senior Secured Notes. As of December 31, 2021, the remaining aggregate principal amount of 2026 Senior Notes outstanding was $289.4 million.
The Senior Unsecured Notes are fully and unconditionally guaranteed on a senior unsecured basis by the Company and each of CRP’s current subsidiaries that guarantee CRP’s revolving credit facility.
At any time prior to January 15, 2021 (for the 2026 Senior Notes) and April 1, 2022 (for the 2027 Senior Notes), the “Optional Redemption Dates,” CRP may, on any one or more occasions, redeem up to 35 105.375 % (for the 2026 Senior Notes) and 106.875 % (for the 2027 Senior Notes) of the principal
73
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
amount of the Senior Unsecured Notes of the applicable series redeemed, plus accrued and unpaid interest to the date of redemption; provided that at least 65 180 days of the closing date of such equity offering.
At any time prior to Optional Redemption Dates, CRP may, on any one or more occasions, redeem all or a part of the Senior Unsecured Notes at a redemption price equal to 100 % of the principal amount of the Senior Unsecured Notes redeemed, plus a “make-whole” premium, and any accrued and unpaid interest as of the date of redemption. On and after the Optional Redemption Dates, CRP may redeem the Senior Unsecured Notes, in whole or in part, at redemption prices expressed as percentages of principal amount plus accrued and unpaid interest to the redemption date.
If CRP experiences certain defined changes of control (and, in some cases, followed by a ratings decline), each holder of the Senior Unsecured Notes may require CRP to repurchase all or a portion of its Senior Unsecured Notes for cash at a price equal to 101
The indentures governing the Senior Unsecured Notes contain covenants that, among other things and subject to certain exceptions and qualifications, limit CRP’s ability and the ability of CRP’s restricted subsidiaries to: (i) incur or guarantee additional indebtedness or issue certain types of preferred stock; (ii) pay dividends on capital stock or redeem, repurchase or retire capital stock or subordinated indebtedness; (iii) transfer or sell assets; (iv) make investments; (v) create certain liens; (vi) enter into agreements that restrict dividends or other payments from their subsidiaries to them; (vii) consolidate, merge or transfer all or substantially all of their assets; (viii) engage in transactions with affiliates; and (ix) create unrestricted subsidiaries. CRP was in compliance with these covenants as of December 31, 2021 and through the filing of this Annual Report.
Upon an Event of Default (as defined in the indentures governing the Senior Unsecured Notes), the trustee or the holders of at least 25
Note 5—Asset Retirement Obligations
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
| Asset retirement obligations, beginning of period | $ | $ | |||||||||
| Liabilities incurred | |||||||||||
| Liabilities on acquired properties | |||||||||||
| Liabilities divested and settled | ( | ( | |||||||||
| Accretion expense | |||||||||||
| Revision to estimated cash flows | ( | ||||||||||
| Asset retirement obligations, end of period | $ | $ | |||||||||
ARO reflect the present value of the estimated future costs associated with the plugging and abandonment of oil and gas wells, removal of equipment and facilities from leased acreage and land restoration in accordance with applicable local, state and federal laws. Inherent in the fair value calculation of ARO are numerous estimates and assumptions, including plug and abandonment settlement amounts, inflation factors, credit adjusted discount rates and the timing of settlement. To the extent future revisions to these assumptions impact the value of the existing ARO liabilities, a corresponding offsetting adjustment is made to the oil and gas property balance. Changes in the liability due to the passage of time are recognized as an increase in the carrying amount of the liability with an offsetting charge to accretion expense, which is included within depreciation, depletion and amortization.
74
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 6—Stock-Based Compensation
On October 7, 2016, the stockholders of the Company approved the Centennial Resource Development, Inc. 2016 Long Term Incentive Plan (the “LTIP”), which authorized an aggregate of 16,500,000 shares of Common Stock for issuance to employees and directors. On April 29, 2020, the stockholders of the Company approved the amended and restated LTIP which, among other things, increased the number of shares of Common Stock authorized for issuance by 8,250,000 shares. The LTIP provides for grants of restricted stock, stock options (including incentive stock options and nonqualified stock options), restricted stock units (including performance stock units), stock appreciation rights and other stock or cash-based awards.
Stock-based compensation expense is recognized within both General and administrative expenses and Exploration and other expenses in the consolidated statements of operations. The Company accounts for forfeitures of awards granted under the LTIP as they occur in determining compensation expense.
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Equity Awards | |||||||||||||||||
| Restricted stock | $ | $ | $ | ||||||||||||||
| Stock option awards | |||||||||||||||||
| Performance stock units | |||||||||||||||||
Other stock-based compensation expense(1) | |||||||||||||||||
| Total stock-based compensation - equity awards | |||||||||||||||||
| Liability Awards | |||||||||||||||||
| Restricted stock units | |||||||||||||||||
| Performance stock units | |||||||||||||||||
| Total stock-based compensation - liability awards | |||||||||||||||||
| Total stock-based compensation expense | $ | $ | $ | ||||||||||||||
Equity Awards
The Company has restricted stock, stock options and performance stock units (“PSUs”) outstanding that were granted under the LTIP as discussed below. Each award has service-based and, in the case of the PSUs, market-based vesting requirements, and are expected to be settled in shares of Common Stock upon vesting. As a result, these awards are classified as equity-based awards in accordance with ASC Topic 718, Compensation-Stock Compensation (“ASC 718”).
Restricted Stock
| Restricted Stock | Weighted Average Fair Value | ||||||||||
| Unvested balance as of December 31, 2020 | $ | ||||||||||
| Granted | |||||||||||
| Vested | ( | ||||||||||
| Forfeited | ( | ||||||||||
| Unvested balance as of December 31, 2021 | |||||||||||
The Company grants service-based restricted stock to executive officers and employees, which vest ratably over a three-year service period, and to directors, which vest over a one-year service period. Compensation cost for these service-based restricted stock is based on the closing market price of the Company’s Common Stock on the grant date, and such costs are recognized ratably over the applicable vesting period. There were 3.1 million shares of restricted stock granted during the year ended December 31, 2021, including 0.6 million shares of restricted stock units that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company intends and has the ability to settle these restricted stock units in Common Stock upon vesting and has treated them as equity-based awards accordingly. The weighted average fair value for restricted stock
75
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
granted was $5.25 , $1.12 and $6.59 per share for the years ended December 31, 2021, 2020 and 2019, respectively. The total fair value of restricted stock that vested for the years ended December 31, 2021, 2020 and 2019 was $15.1 million, $17.4 million and $12.0 million, respectively. Unrecognized compensation cost related to restricted shares that were unvested as of December 31, 2021 was $21.8 million, which the Company expects to recognize over a weighted average period of 2.2 years.
Stock Options
Stock options that have been granted under the LTIP expire ten years from the grant date and vest ratably over a three-year service period. The exercise price for an option granted under the LTIP is the closing price of the Company’s Common Stock on the grant date.
Compensation cost for stock options is based on the grant-date fair value of the award, which is then recognized ratably over the vesting period of three years . The Company estimates the fair value using the Black-Scholes option-pricing model. Expected volatilities are based on the weighted average historical volatilities of the Company and an identified set of comparable companies. Expected term is based on the simplified method and is estimated as the mid-point between the weighted average vesting term and the time to expiration as of the grant date. The Company uses U.S. Treasury bond rates in effect at the grant date for its risk-free interest rates.
| Years Ended December 31, | |||||||||||
| 2020 | 2019 | ||||||||||
| Weighted average grant-date fair value per share | $ | $ | |||||||||
| Expected term (in years) | |||||||||||
| Expected stock volatility | % | % | |||||||||
| Dividend yield | |||||||||||
| Risk-free interest rate | % | % | |||||||||
| Options | Weighted Average Exercise Price | Weighted Average Remaining Term (in years) | Aggregate Intrinsic Value (in thousands) | ||||||||||||||||||||
| Outstanding as of December 31, 2020 | $ | ||||||||||||||||||||||
| Granted | |||||||||||||||||||||||
| Exercised | ( | $ | |||||||||||||||||||||
| Forfeited | ( | ||||||||||||||||||||||
| Expired | ( | ||||||||||||||||||||||
| Outstanding as of December 31, 2021 | $ | ||||||||||||||||||||||
| Exercisable as of December 31, 2021 | $ | ||||||||||||||||||||||
The total fair value of stock options that vested during the years ended December 31, 2021, 2020 and 2019 was $1.2 million, $5.7 million and $10.2 million, respectively. The intrinsic value of the stock options exercised during the year ended December 31, 2021 and 2020 was minimal, and there were no stock options exercised during the year ended December 31, 2019. As of December 31, 2021, there was $0.1 million of unrecognized compensation cost related to unvested stock options, which the Company expects to recognize on a pro-rata basis over a weighted-average period of 0.8 years.
Performance Stock Units
The Company grants performance stock units to certain executive officers that are subject to market-based vesting criteria as well as a three-year service period. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or decreases by a lesser percentage, than the average percentage increase or decrease, respectively, of the stock prices of a peer group of companies. These market-based conditions must be met in order for these stock awards to vest, and it is therefore possible that no shares could ultimately vest. However, the Company recognizes compensation expense for these performance stock units subject to market conditions regardless of whether such conditions are met or not, and compensation expense is not reversed if vesting does not actually occur.
76
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
During the year ended December 31, 2021, there were 1.1 million shares of performance stock units granted that can be settled in either Common Stock or cash upon vesting at the Company’s discretion. The Company intends to settle these performance stock units in Common Stock and has treated them as equity-based awards accordingly. These performance stock units were legally granted to certain executive officers. At this time, however, the Company currently does not have sufficient shares available under the LTIP to settle the units in Common Stock at the potential future vesting date in the third quarter 2024. As a result, a grant date, in accordance with ASC 718, has not yet been fully achieved, and the awards’ fair value will be re-measured as of each balance sheet date. Stock compensation expense amounts recognized in future periods for these awards will vary until sufficient shares are available under the LTIP and all grant date criteria have been satisfied accordingly. The information included in the tables below reflects the fair value of the performance stock units as of December 31, 2021.
The fair value was estimated using a Monte Carlo valuation model. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s Common Stock, and the risk-free interest rate is based on U.S. Treasury yield curve rates with maturities consistent with the three-year vesting period.
| Years Ended December 31, | |||||||||||
| 2021 | 2019 | ||||||||||
| Weighted average fair value per unit | $ | $ | |||||||||
| Number of simulations | |||||||||||
| Expected stock volatility | % | % | |||||||||
| Dividend yield | % | % | |||||||||
| Risk-free interest rate | % | % | |||||||||
| Awards | Weighted Average Fair Value | ||||||||||
| Unvested balance as of December 31, 2020 | $ | ||||||||||
| Granted | |||||||||||
| Vested | |||||||||||
| Cancelled | ( | ||||||||||
| Forfeited | |||||||||||
| Unvested balance as of December 31, 2021 | |||||||||||
As of December 31, 2021, there was $9.3 million of unrecognized compensation cost related to unvested performance stock units, which the Company expects to recognize on a pro rata basis over a weighted average period of 2.5 years
Liability Awards
The Company has restricted stock units and performance stock units that were granted under the LTIP, which will be settled in cash and are classified as liability awards in accordance with ASC 718. Compensation cost for the liability awards is based on the fair value of the units as of the balance sheet date as further discussed below, and such costs are recognized ratably over the service periods of the awards. As the fair value of liability awards is required to be re-measured each period end, stock compensation expense amounts recognized in future periods for these awards will vary. The estimated future cash payments of these awards are presented as liabilities within Other long-term liabilities in the consolidated balances sheets.
Restricted Stock Units
The Company granted 5.5 million restricted stock units during the third quarter of 2020 to certain officers (non-NEOs) and employees that are settleable in cash upon vesting. The restricted stock units vest annually in one-third increments over a three-year service period, with the first portion vesting on September 1, 2021. After one year from the grant date, however, the restricted stock units can vest immediately on an accelerated basis if they meet certain market-based vesting criteria (equal to the maximum return percentage discussed below for at least 20 out of any 30 consecutive trading days). Additionally, the restricted stock units include maximum and minimum return amounts equal to 400 % and 25 %, respectively, of the closing market price of the Company’s common stock on the grant date.
77
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The Company amended these restricted stock unit agreements to (i) allow the units to be settleable in either cash or Common Stock upon vesting at the Company’s discretion and (ii) remove the maximum and minimum return amounts if the units are settled in Common Stock. The amended terms were effective July 1, 2021, and at the time, the Company intended to settle a portion of these restricted stock units in cash. As a result, the awards continued to be classified as liabilities in accordance with ASC 718.
During the year ended December 31, 2021, the maximum return event (described above) occurred resulting in an immediate vesting of all the outstanding restricted stock units on September 1, 2021. The Company settled 1.8 million of the restricted stock units in cash resulting in a $6.2 million cash payment, and the remaining units were settled in Common Stock. The portion of the units that were settled in Common Stock were recognized as equity instruments on the vesting date, which resulted in $13.6 million of incremental stock compensation expense being recognized during the year ended December 31, 2021.
Performance Stock Units
The Company granted 5.5 million performance stock units (“PSU”) during the third quarter of 2020 to certain executive officers that will be settled in cash that are subject to market-based vesting criteria as well as a three-year service condition. Vesting at the end of the three-year service period is subject to the condition that the Company’s stock price increases by a greater percentage, or decreases by a lessor percentage, than the average percentage increase or decrease, respectively, of the stock price of a peer group of companies. The market-based conditions must be met in order for the PSU awards to vest, and it is therefore possible that no units could ultimately vest and cumulative stock compensation expense recognized for these awards would then be reduced to zero. As of December 31, 2021, there was $25.3 million of unrecognized compensation cost, which represents the unvested portion of the fair value of the PSUs at December 31, 2021, and which will be recognized over a weighted average period of 1.5 years.
Liability Awards Fair Value
The fair value of the performance stock units was estimated using a Monte Carlo valuation model as of the balance sheet date. The Monte Carlo valuation model is based on random projections of stock price paths and must be repeated numerous times to achieve a probabilistic assessment. Expected volatility was calculated based on the historical volatility of the Company’s common stock as well as the peer companies that are specified in the PSU award agreement. The risk-free rate is based on U.S. Treasury yield curve rates with maturities consistent with the remaining vesting or performance period.
| Performance stock units | |||||
| Number of simulations | |||||
| Expected stock volatility | % | ||||
| Dividend yield | % | ||||
| Risk-free interest rate | % | ||||
Note 7—Derivative Instruments
The Company is exposed to certain risks relating to its ongoing business operations and may use derivative instruments to manage its exposure to commodity price risk from time to time.
Commodity Derivative Contracts
Historically, prices received for crude oil and natural gas production have been volatile because of supply and demand factors, worldwide political factors, general economic conditions and seasonal weather patterns. The Company may periodically use derivative instruments, such as swaps, costless collars and basis swaps, to mitigate its exposure to declines in commodity prices and to the corresponding negative impacts such declines can have on its cash flow from operations, returns on capital and other financial results. While the use of these instruments limits the downside risk of adverse price changes, their use may also limit future revenues from favorable price changes. The Company does not enter into derivative contracts for speculative or trading purposes.
Commodity Swap and Collar Contracts. The Company may use commodity derivative instruments known as fixed price swaps to realize a known price for a specific volume of production, basis swaps to hedge the difference between the index price and a local index price, or costless collars to establish fixed price floors and ceilings. All transactions are settled in cash with one party paying the other for the resulting difference in price multiplied by the contract volume.
78
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
The following table summarizes the approximate volumes and average contract prices of derivative contracts the Company had in place as of December 31, 2021:
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Crude Price ($/Bbl)(1) | ||||||||||||||||||||
Crude oil swaps | January 2022 - March 2022 | $ | |||||||||||||||||||||
| April 2022 - June 2022 | |||||||||||||||||||||||
| July 2022 - September 2022 | |||||||||||||||||||||||
| October 2022 - December 2022 | |||||||||||||||||||||||
| January 2023 - March 2023 | |||||||||||||||||||||||
| April 2023 - June 2023 | |||||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Collar Price Ranges ($/Bbl)(2) | ||||||||||||||||||||||||||
Crude oil collars | January 2022 - March 2022 | $ | - | $ | |||||||||||||||||||||||||
| April 2022 - June 2022 | - | ||||||||||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(3) | ||||||||||||||||||||
Crude oil basis differential swaps | January 2022 - March 2022 | $ | |||||||||||||||||||||
| April 2022 - June 2022 | |||||||||||||||||||||||
| July 2022 - September 2022 | |||||||||||||||||||||||
| October 2022 - December 2022 | |||||||||||||||||||||||
| Period | Volume (Bbls) | Volume (Bbls/d) | Wtd. Avg. Differential ($/Bbl)(4) | ||||||||||||||||||||
Crude oil roll differential swaps | January 2022 - March 2022 | $ | |||||||||||||||||||||
| April 2022 - June 2022 | |||||||||||||||||||||||
| July 2022 - September 2022 | |||||||||||||||||||||||
| October 2022 - December 2022 | |||||||||||||||||||||||
(1) These crude oil swap transactions are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These crude oil collars are settled based on the NYMEX WTI index price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
(3) These crude oil basis swap transactions are settled based on the difference between the arithmetic average of ARGUS MIDLAND WTI and ARGUS WTI CUSHING indices, during each applicable monthly settlement period.
(4) These crude oil roll swap transactions are settled based on the difference between the arithmetic average of NYMEX WTI calendar month prices and the physical crude oil delivery month price.
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Gas Price ($/MMBtu)(1) | ||||||||||||||||||||
Natural gas swaps | January 2022 - March 2022 | $ | |||||||||||||||||||||
| April 2022 - June 2022 | |||||||||||||||||||||||
| July 2022 - September 2022 | |||||||||||||||||||||||
| October 2022 - December 2022 | |||||||||||||||||||||||
79
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Collar Price Ranges ($/MMBtu)(2) | ||||||||||||||||||||||||||
Natural gas collars | January 2022 - March 2022 | $ | - | $ | |||||||||||||||||||||||||
| April 2022 - June 2022 | - | ||||||||||||||||||||||||||||
| July 2022 - September 2022 | - | ||||||||||||||||||||||||||||
| October 2022 - December 2022 | - | ||||||||||||||||||||||||||||
| Period | Volume (MMBtu) | Volume (MMBtu/d) | Wtd. Avg. Differential ($/MMBtu)(3) | ||||||||||||||||||||
Natural gas basis differential swaps | January 2022 - March 2022 | $( | |||||||||||||||||||||
| April 2022 - June 2022 | ( | ||||||||||||||||||||||
| July 2022 - September 2022 | ( | ||||||||||||||||||||||
| October 2022 - December 2022 | ( | ||||||||||||||||||||||
| January 2023 - March 2023 | ( | ||||||||||||||||||||||
| April 2023 - June 2023 | ( | ||||||||||||||||||||||
| July 2023 - September 2023 | ( | ||||||||||||||||||||||
| October 2023 - December 2023 | ( | ||||||||||||||||||||||
(1) These natural gas swap contracts are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual swap price for the volumes stipulated.
(2) These natural gas collars are settled based on the NYMEX Henry Hub price on each trading day within the specified monthly settlement period versus the contractual floor and ceiling prices for the volumes stipulated.
Derivative Instrument Reporting. The Company’s oil and natural gas derivative instruments have not been designated as hedges for accounting purposes. Therefore, all gains and losses are recognized in the Company’s consolidated statements of operations. All derivative instruments are recorded at fair value in the consolidated balance sheets, other than derivative instruments that meet the “normal purchase normal sale” exclusion, and any fair value gains and losses are recognized in current period earnings.
| Year Ended December 31, | |||||||||||||||||
(in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
Net gain (loss) on derivative instruments | $ | ( | $ | ( | $ | ( | |||||||||||
Offsetting of Derivative Assets and Liabilities. The Company’s commodity derivatives are included in the accompanying consolidated balance sheets as derivative assets and liabilities. The Company nets its financial derivative instrument fair value amounts executed with the same counterparty pursuant to ISDA master netting agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The tables below summarize the fair value amounts and classification in the consolidated balance sheets of the Company’s derivative contracts outstanding at the respective
80
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
balance dates, as well as the gross recognized derivative assets, liabilities and offset amounts:
| Balance Sheet Classification | Gross Fair Value Asset/Liability Amounts | Gross Amounts Offset(1) | Net Recognized Fair Value Assets/Liabilities | ||||||||||||||||||||
(in thousands) | December 31, 2021 | ||||||||||||||||||||||
Derivative Assets | |||||||||||||||||||||||
Commodity contracts | Prepaid and other current assets | $ | $ | ( | $ | ||||||||||||||||||
| Other noncurrent assets | ( | ||||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Other current liabilities | $ | $ | ( | $ | ||||||||||||||||||
| Other noncurrent liabilities | ( | ||||||||||||||||||||||
| December 31, 2020 | |||||||||||||||||||||||
Derivative Assets | |||||||||||||||||||||||
Commodity contracts | Prepaid and other current assets | $ | $ | ( | $ | ||||||||||||||||||
| Other noncurrent assets | ( | ||||||||||||||||||||||
Derivative Liabilities | |||||||||||||||||||||||
Commodity contracts | Other current liabilities | $ | $ | ( | $ | ||||||||||||||||||
| Other noncurrent liabilities | ( | ||||||||||||||||||||||
(1) The Company has agreements in place with all of its counterparties that allow for the financial right of offset for derivative assets against derivative liabilities at settlement or in the event of a default under the agreements or contract termination.
Contingent Features in Financial Derivative Instruments. None of the Company’s derivative instruments contain credit-risk-related contingent features. Counterparties to the Company’s financial derivative contracts are high credit-quality financial institutions that are lenders under CRP’s Credit Agreement. The Company uses only Credit Agreement participants to hedge with, since these institutions are secured equally with the holders of any CRP bank debt, which eliminates the potential need to post collateral when Centennial is in a derivative liability position. As a result, the Company is not required to post letters of credit or corporate guarantees for its derivative counterparties in order to secure contract performance obligations.
In addition, the Company is exposed to credit risk associated with its derivative contracts from non-performance by its counterparties. The Company mitigates its exposure to any single counterparty by contracting with a number of financial institutions, each of which has a high credit rating and is a member of CRP’s credit facility as referenced above.
Note 8—Fair Value Measurements
Recurring Fair Value Measurements
The Company follows ASC Topic 820, Fair Value Measurement and Disclosure, which establishes a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:
•Level 1: Quoted Prices in Active Markets for Identical Assets – inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.
•Level 2: Significant Other Observable Inputs – inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability, either directly or indirectly, for substantially the full term of the financial instrument.
•Level 3: Significant Unobservable Inputs – inputs to the valuation methodology are unobservable and significant to the fair value measurement.
81
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
(in thousands) | Level 1 | Level 2 | Level 3 | ||||||||||||||
| December 31, 2021 | |||||||||||||||||
Total assets | $ | $ | $ | ||||||||||||||
Total liabilities | |||||||||||||||||
| December 31, 2020 | |||||||||||||||||
Total assets | $ | $ | $ | ||||||||||||||
Total liabilities | |||||||||||||||||
Both financial and non-financial assets and liabilities are categorized within the above fair value hierarchy based on the lowest level of input that is significant to the fair value measurement. The Company’s assessment of the significance of a particular input to the fair value measurement in its entirety requires judgement and considers factors specific to the asset or liability. The following is a description of the valuation methodologies used by the Company as well as the general classification of such instruments pursuant to the above fair value hierarchy. There were no transfers between any of the fair value levels during any period presented.
Derivatives
The Company uses Level 2 inputs to measure the fair value of its oil and natural gas commodity derivatives. The Company uses industry-standard models that consider various assumptions including current market and contractual prices for the underlying instruments, implied market volatility, time value, nonperformance risk, as well as other relevant economic measures. Substantially all of these inputs are observable in the marketplace throughout the full term of the instrument and can be supported by observable data. The Company utilizes its counterparties’ valuations to assess the reasonableness of its own valuations. Refer to Note 7—Derivative Instruments for details of the gross and net derivative assets, liabilities and offset amounts as presented in the consolidated balance sheets.
Nonrecurring Fair Value Measurements
The Company applies the provisions of the fair value measurement standard on a nonrecurring basis to its non-financial assets and liabilities, including proved oil and gas properties. These assets and liabilities are not measured at fair value on an ongoing basis but are subject to fair value adjustments in certain circumstances.
Impairment of Oil and Natural Gas Properties. The Company reviews its proved oil and natural gas properties for impairment whenever events and circumstances indicate that the fair value of these assets may be below their carrying value. The significant decrease in the forward price curves for crude oil and natural gas in March of 2020 resulted in a triggering event which required the Company to reassess its proved oil and natural gas properties for impairment as of March 31, 2020. An impairment loss is indicated if the sum of the expected undiscounted future net cash flows from oil and gas properties is less than the carrying amount of the assets. In this circumstance, the Company then recognizes impairment expense for the amount by which the carrying amount of proved properties exceeds their estimated fair value. The Company reviews its oil and natural gas properties on a field-by-field basis.
The Company calculates the estimated fair values of its oil and natural gas properties using an income approach that is based on inputs that are not observable in the market and therefore represent Level 3 inputs. Significant inputs to the expected future net cash flows used for the impairment review and the related fair value measurement of oil and natural gas proved properties include estimates of: (i) reserves; (ii) future production decline rates; (iii) future operating and development costs; (iv) future commodity prices, including price differentials; and (v) a market participant-based weighted average cost of capital rate. These inputs require significant judgments and estimates by the Company’s management.
The impairment test performed by the Company indicated that a proved property impairment had occurred with respect to certain of its oil and gas fields, and therefore a non-cash impairment charge to reduce the carrying value of the impaired property to its fair value was recorded. Proved oil and natural gas properties with a previous carrying value of $771.4 million were partially written down to their fair value of $179.6 million, resulting in a noncash impairment charge of $591.8 million being recorded in the first quarter of 2020. All of the Company’s proved oil and gas properties were included in the impairment assessment performed as of March 31, 2020. Two of the Company’s fields were subject to an impairment write-down as quantified above, but the remaining five fields were not impaired due to their undiscounted cash flows exceeding their carrying values by 30 % to over 100 %. The Company did not recognize any additional impairment write-downs with respect to its proved property during the remainder of the year ending December 31, 2020 or during the year ended December 31, 2021. Impairment expense for proved properties is presented as part of Impairment and Abandonment Expense in the consolidated statements of operations.
82
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Asset Retirement Obligations. The initial measurement of ARO at fair value is calculated using discounted cash flow techniques and is based on internal estimates of future retirement costs associated with property, plant and equipment. Significant Level 3 inputs used in the calculation of ARO include the estimated future costs to plug and abandon oil and gas properties and reserve lives. Refer to Note 5—Asset Retirement Obligations for additional information on the Company’s ARO.
Senior Secured Notes. The Company’s Senior Secured Notes were measured and recorded at their fair value on the date of issuance equal to 83.44 % of par. The fair value was determined utilizing the Black-Derman-Toy binomial lattice model, which is a one-factor binomial lattice model that determines the future evolution of the relevant yields. For each node on the lattice, it is determined whether it is preferable to redeem, or not, based on the yields. The model utilizes both a yield curve and a yield volatility as of the valuation date, both of which are estimated based on yields of comparable debt instruments and are inputs that are not observable for the Senior Secured Notes for the term of the debt instrument (a Level 3 classification in the fair value hierarchy). The fair value was measured by the model using the following inputs: (i) the treasury yield curve as of the valuation date, (ii) 12 % credit spread, (iii) 45 % yield volatility, and (iv) a corporate credit rating of B. The Company has not elected the fair value option, which would require remeasurement at fair value each period, to account for this debt instrument.
Other Financial Instruments
The carrying amounts of the Company’s cash, cash equivalents, accounts receivable, accounts payable, and accrued liabilities approximate their fair values because of the short-term maturities and/or liquid nature of these assets and liabilities.
The Company’s senior notes and borrowings under its Credit Agreement are accounted for at cost, and the cost basis of the Company’s Senior Secured Notes issued in the Debt Exchange was measured based on their fair value on the date of the exchange, as discussed above. The following table summarizes the fair values and carrying values of these instruments as of the periods indicated:
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||||||||||||||
| Carrying Value | Principal Amount | Fair Value | Carrying Value | Principal Amount | Fair value | |||||||||||||||||||||||||||||||||
Credit Facility due 2023(1) | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||
(1) The carrying values of the amounts outstanding under CRP’s Credit Agreement approximate fair value because its variable interest rates are tied to current market rates and the applicable credit spreads represent current market rates for the credit risk profile of the Company.
(2) The carrying values include associated unamortized debt issuance costs and any debt discounts as reflected in the consolidated balance sheets. The fair values are determined using quoted market prices for these debt securities, a Level 1 classification in the fair value hierarchy, and are based on the aggregate principal amount of the senior notes outstanding.
Note 9—Shareholders' Equity and Noncontrolling Interest
On April 2, 2020, the legacy owners of CRP (the “Centennial Contributors”) converted all of their remaining 1,034,119 CRP Common Units (and corresponding shares of Class C Common Stock) into Common Stock (the “Conversion”), which eliminated the noncontrolling interest ownership in CRP. No cash proceeds were received by the Company in connection with the Conversion, and deferred tax expense of $2.2 million was recorded in equity.
During 2019, the Centennial Contributors converted 10,969,064 of their CRP Common Units (and corresponding shares of Class C Common Stock) into Common Stock. No cash proceeds were received by the Company and deferred tax expense of $17.5 million was recorded in equity as a result of the conversion of shares from the noncontrolling interest owner.
83
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Class A Common Stock
Holders of the Company's Common Stock are entitled to one vote for each share held on all matters submitted to a vote by the Company's stockholders, except as required by law. Unless specified in the Company’s second amended and restated certificate of incorporation (the “Charter”) (including any certificate of designation of preferred stock) or the Company’s second amended and restated bylaws, or as required by applicable provisions of the Delaware General Corporation Law or applicable stock exchange rules, the affirmative vote of a majority of the Company’s shares of common stock that are voted is required to approve any such matter voted on by the Company’s stockholders. There is no cumulative voting with respect to the election of directors, with the result that the holders of more than 50 % of the shares voted for the election of directors can elect all of the directors. Subject to the rights of the holders of any outstanding series of preferred stock, the holders of the Common Stock are entitled to receive ratable dividends when, as and if declared by the board of directors out of funds legally available therefor.
In the event of a liquidation, dissolution or winding up of the Company, the holders of the Common Stock are entitled to share ratably in all assets remaining available for distribution to them after payment of liabilities and after provision is made for each class of stock, if any, having preference over the Common Stock. The holders of the Common Stock have no preemptive or other subscription rights. There are no sinking fund provisions applicable to the Common Stock.
Class C Common Stock
The Company had no 20,000,000 shares of Class C Common Stock issued to the Centennial Contributors in connection with the acquisition of approximately 89 % of the outstanding membership interests in CRP, consummated on October 11, 2016 (the “Business Combination”).
Prior to the Conversion, holders of Class C Common Stock, together with holders of the Common Stock voting as a single class, had the right to vote on all matters properly submitted to a vote of the stockholders. In addition, the holders of Class C Common Stock, voting as a separate class, were entitled to approve any amendment, alteration or repeal of any provision of the Charter that would alter or change the powers, preferences or relative, participating, optional, other or special rights of the Class C Common Stock. Holders of Class C Common Stock were not entitled to any dividends from the Company and were not entitled to receive any of its assets in the event of any voluntary or involuntary liquidation, dissolution or winding up of its affairs.
Shares of Class C Common Stock were only allowed to be issued to the Centennial Contributors, their respective successors and assigns, as well as any permitted transferees of the Centennial Contributors. Holders of Class C Common Stock had the right to cause CRP to redeem all or a portion of their CRP Common Units in exchange for shares of the Company’s Common Stock or, at CRP’s option, an equivalent amount of cash.
Preferred Stock
In connection with the Business Combination, the Company issued one share of Series A Preferred Stock at par value, $0.0001 per share (the “Series A Preferred Stock”) to one of the Centennial Contributors. The Series A Preferred Stock provided the holder thereof with the right to nominate and elect one director to the Company’s Board of Directors, but it did not provide any other voting rights or rights with respect to dividends except distributions in liquidation in the amount of $0.0001 per share. In July 2020, the Company redeemed the one share of Series A Preferred Stock after NGP X US Holdings, L.P., the current holder of the share of Series A Preferred Stock and a former indirect equity owner of CRP, ceased to own, in the aggregate, at least 5,000,000 CRP Common Units and/or shares of Common Stock.
Warrants
Simultaneously with the closing of the Company’s initial public offering on February 29, 2016, 8,000,000 warrants were purchased by Silver Run Sponsor, LLC, an affiliate of Riverstone Investment Group LLC and its affiliates (“Riverstone”), in a private placement (the “Private Placement Warrants”). The Private Placement Warrants were non-redeemable so long as they are held by Riverstone or its permitted transferees. Each Private Placement Warrant was exercisable for one share of Common Stock at a price of $11.50 per share. The Private Placement Warrants became exercisable on March 1, 2017 but expired on October 11, 2021 unexercised.
Noncontrolling Interest
The noncontrolling interest relates to CRP Common Units that were issued to the Centennial Contributors in connection with the Business Combination. At the date of the Business Combination, the noncontrolling interest held 10.9 % of the ownership in CRP. The noncontrolling interest percentage is affected by various equity transactions such as CRP Common Unit and Class C Common Stock exchanges and Class A Common Stock activities.
84
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
As of December 31, 2019, the noncontrolling interest ownership of CRP decreased to 0.37 % as a result of the exchange of CRP Common Units (and corresponding shares of Class C Common Stock) for Common Stock. As of December 31, 2021 and 2020, the noncontrolling interest ownership of CRP was reduced to zero
The Company consolidated the results of operations and cash flows of CRP and reflected the portion retained by other holders of CRP Common Units as a noncontrolling interest through the date of the Conversion. Refer to the consolidated statements of shareholders’ equity for a summary of the activity attributable to the noncontrolling interest during the periods.
Note 10—Earnings Per Share
Basic earnings per share (“EPS”) is calculated by dividing net income available to Class A Common Stock by the weighted average shares of Class A Common Stock outstanding during each period. Dilutive EPS is calculated by dividing adjusted net income available to Class A Common Stock by the weighted average shares of diluted Class A Common Stock outstanding, which includes the effect of potentially dilutive securities. Potentially dilutive securities for the diluted EPS calculation consists of (i) unvested equity based restricted stock and performance stock units, outstanding stock options, withholding amounts from employee stock purchase plan and Private Placement Warrants (prior to their expiration discussed above) using the treasury stock method, and (ii) the Company’s Class C Common Stock outstanding prior to the Conversion and potential shares issuable under our Convertible Senior Notes, both using the “if-converted” method, which is net of tax. When a loss from continuing operations exists, all dilutive securities and potentially dilutive securities are anti-dilutive and therefore excluded from the computation of diluted earnings per share.
| Year Ended December 31, | |||||||||||||||||
| (in thousands, except per share data) | 2021 | 2020 | 2019 | ||||||||||||||
| Net income attributable to Class A Common Stock | $ | $ | ( | $ | |||||||||||||
| Add: Income from Convertible Senior Notes | |||||||||||||||||
| Add: Income from conversion of Class C Common Stock | |||||||||||||||||
| Adjusted net income attributable to Class A Common Stock | $ | $ | ( | $ | |||||||||||||
| Basic weighted average shares of Class A Common Stock outstanding | |||||||||||||||||
| Add: Dilutive effects of Convertible Senior Notes | |||||||||||||||||
| Add: Dilutive effects of conversion of Class C Common Stock | |||||||||||||||||
| Add: Dilutive effects of potential common stock | |||||||||||||||||
| Diluted weighted average shares of Class A Common Stock outstanding | |||||||||||||||||
| Basic net earnings per share of Class A Common Stock | $ | $ | ( | $ | |||||||||||||
| Diluted net earnings per share of Class A Common Stock | $ | $ | ( | $ | |||||||||||||
The following table presents shares excluded from the diluted earnings per share calculation as their impacts were anti-dilutive for the periods presented:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020(1) | 2019 | ||||||||||||||
| Out-of-the-money stock options | |||||||||||||||||
| Restricted stock | |||||||||||||||||
| Performance stock units | |||||||||||||||||
| Employee Stock Purchase Plan | |||||||||||||||||
| Weighted average shares of Class C Common Stock | |||||||||||||||||
| Private Placement Warrants | |||||||||||||||||
85
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 11—Income Taxes
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Current taxes | |||||||||||||||||
| Federal | $ | $ | $ | ||||||||||||||
| State | ( | ||||||||||||||||
| ( | |||||||||||||||||
| Deferred taxes | |||||||||||||||||
| Federal | ( | ||||||||||||||||
| State | ( | ||||||||||||||||
| ( | |||||||||||||||||
| Income tax (expense) benefit | $ | ( | $ | $ | ( | ||||||||||||
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Income tax (expense) benefit at the federal statutory rate | $ | ( | $ | $ | ( | ||||||||||||
| State income tax (expense) benefit - net of federal benefit | ( | ( | |||||||||||||||
| Noncontrolling interest in partnership | ( | ||||||||||||||||
| Nondeductible stock-based and other compensation | ( | ( | ( | ||||||||||||||
| Nondeductible expenses | ( | ( | ( | ||||||||||||||
| Change in valuation allowance | ( | ||||||||||||||||
| Income tax (expense) benefit | $ | ( | $ | $ | ( | ||||||||||||
86
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
| Deferred tax assets: | |||||||||||
| Net operating loss carryforwards | $ | $ | |||||||||
| Capitalized intangible drilling costs | |||||||||||
| Stock-based compensation | |||||||||||
| Derivative assets | |||||||||||
| Asset retirement obligations | |||||||||||
| Other assets | |||||||||||
| Total deferred tax assets | |||||||||||
| Deferred tax liabilities: | |||||||||||
| Oil and gas properties | ( | ( | |||||||||
| Other liabilities | ( | ||||||||||
| Total deferred tax liabilities | ( | ( | |||||||||
| Valuation allowance | ( | ( | |||||||||
| Net deferred tax asset (liability) | $ | ( | $ | ( | |||||||
As of December 31, 2021, the Company had approximately $496.2 million and $132.4 million of U.S. federal and state net operating loss carryovers, respectively. Approximately $417.4 million and $78.2 million of these U.S. federal and state net operating loss carryovers expire in 2037, respectively.
The Company periodically assesses whether it is more-likely-than-not that it will generate sufficient taxable income to realize its deferred income tax assets, including net operating loss carry forwards. In making this determination, the Company considers all available positive and negative evidence and makes certain assumptions. The Company considers, among other things, its deferred tax liabilities, the overall business environment, its historical earnings and losses, current industry trends, and its outlook for future years. Based on when the Company expects existing taxable differences to be realized, management determined that sufficient negative evidence exists as of December 31, 2021 to conclude that it is more-likely-than-not that a portion of its deferred tax assets will not be realized. Accordingly, a valuation allowance against its deferred tax assets in the amount of $77.0 million was recorded as of December 31, 2020. During the year ended December 31, 2021, the valuation allowance was reduced by $36.9 million as a result of net income generated during the year.
The calculation of the Company’s tax liabilities involves uncertainties in the application of complex tax laws and regulations. The Company gives financial statement recognition to those tax positions that it believes are more-likely-than-not to be sustained upon the examination by the Internal Revenue Service or other governmental agency. As of December 31, 2021 and 2020, the Company did not have any accrued liability for uncertain tax positions and does not anticipate recognition of any significant liabilities for uncertain tax positions during the next 12 months. Interest and penalties related to uncertain tax positions are reported in income tax expense.
The Company is subject to the following material taxing jurisdictions: U.S., Colorado, New Mexico, and Texas. As of December 31, 2021, the Company has no current tax years under audit. The Company remains subject to examination for federal income taxes and state income taxes for tax years 2017 through 2021.
87
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 12—Transactions with Related Parties
Riverstone beneficially own more than 10% equity interest in the Company and are therefore considered related parties. The Company has a marketing agreement with Lucid Energy Delaware, LLC (“Lucid”), an affiliate of Riverstone. The Company believes that the term of the marketing agreement with Lucid are no less favorable to either party than those held with unaffiliated parties.
The following table summarizes the revenues recognized and the associated processing fees incurred from this marketing agreement as presented in the consolidated statements of operations for the periods indicated as well as the related net receivables outstanding as of the balance sheet dates:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Lucid Energy Delaware, LLC (“Lucid”) | |||||||||||||||||
| Oil and gas sales | $ | $ | $ | ||||||||||||||
| Gathering, processing and transportation expenses | |||||||||||||||||
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
Accounts receivable, net(1) | $ | $ | |||||||||
Senior Secured Notes
Note 13—Commitments and Contingencies
Contractual Obligations
| (in thousands) | 2022 | 2023 | 2024 | 2025 | 2026 | Thereafter | Total | ||||||||||||||||||||||||||||||||||
| Purchase obligations | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
| Transportation agreements | |||||||||||||||||||||||||||||||||||||||||
| Total | $ | $ | $ | $ | $ | $ | $ | ||||||||||||||||||||||||||||||||||
Purchase Obligations
In 2021, the Company entered into a multi-year energy purchase agreement to buy electricity utilized in our Texas operations. Under the contract, Centennial is obligated to purchase a minimum supply of electricity at a fixed price. If the Company does not utilize the minimum amounts of electricity on a monthly basis and the supplier is unable to sell the unutilized quantity, the Company is liable for the full cost of the underutilization at the fixed price per the agreement. The obligations reported above represent the gross minimum financial commitments pursuant to this agreement as of December 31, 2021. The Company paid electricity costs of $7.9 million for the year ended December 31, 2021 to this supplier.
Transportation Agreements
The Company has various natural gas transportation agreements whereby it is required to pay fixed reservation fees for pipeline capacity over the contractual terms. The obligations reported above represent the gross minimum financial commitments pursuant to these agreements as of December 31, 2021. The Company has an additional gas transport agreement with a volumetric obligation, but this agreement has variable pricing components that cannot reliably be determined and therefore is not included above. Actual expenditures under these contracts are likely to exceed the minimum commitment amounts presented above. The Company paid transportation and gathering costs of $16.1 million, $19.5 million and $12.8 million for the years ended December 31, 2021, 2020 and 2019, respectively, related to these agreements.
88
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Water Disposal Agreement
The Company had agreements for the transportation and disposal of produced water from a portion of its operated wells. Under the terms of these agreements, Centennial was obligated to deliver a minimum volume of produced water or else pay for any deficiencies at the prices stipulated in the contracts. There were minimal remaining financial commitment obligations pursuant to the terms of these contracts as of December 31, 2021. The Company recognized water disposal costs of $2.0 million, $2.4 million and $2.6 million for the years ended December 31, 2021, 2020 and 2019, respectively, related to these water disposal agreements.
Delivery Commitments
In August 2018, the Company entered into a firm crude oil sales agreement with a large integrated oil company that was subsequently amended during the year ended December 31, 2020. Utilizing this company’s transport capacity out of the Permian Basin, the agreement, as amended, provides for firm gross sales of 29,000 Bbls/d over the next 3.5 years and is based upon prevailing market prices of ICE Brent and contractual differentials. These pricing terms are resulting in realized prices that currently have wider differentials than those being realized under the Company’s other oil marketing agreements. However, if the oil price differential between the ICE Brent and NYMEX WTI indices widen in the future, the oil price realized under this delivery commitment will improve relative to the prices realized under the Company’s other oil sales contracts. Under-delivery of volumes would result in a financial obligation to the Company.
The Company has firm gas sales agreements that provide for firm gross sales ranging from approximately 41,000 to 61,000 MMBtu/d in aggregate over the next year. These sales agreements do not require the Company to physically deliver the aforementioned volumes over the terms of the agreements, but if the volumetric commitments are not met and the purchaser incurs financial damages, the Company is required to pay for any differences between the contracted prices and current market prices for replacement volumes bought by the purchaser.
The amounts discussed above represent the total gross volumes the Company is required to deliver per these agreements, which gross volumes are not comparable to the Company’s net production presented in Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation, as amounts therein are reflected net of all royalties, overriding royalties and production due to others. The Company believes its current production and reserves are sufficient to fulfill the physical delivery commitments, and the Company is not required to deliver oil or gas specifically produced from any of the Company’s properties under these agreements. Further, if the Company’s production is not sufficient to satisfy the firm delivery commitments, the Company believes it can purchase sufficient volumes in the market at index-related prices to satisfy its commitments. The aggregate amount of any such potential financial obligation under these contracts is not determinable since the amount and timing of any volumetric shortfalls, as well as the difference between the prevailing market price and contract price at such time, cannot be predicted with accuracy.
Lease Commitments
Refer to Note 15—Leases for details on the Company’s operating lease agreements.
Contingencies
The Company may at times be subject to various commercial or regulatory claims, prior period adjustments from service providers, litigation or other legal proceedings that arise in the ordinary course of business. While the outcome of these lawsuits and claims cannot be predicted with certainty, management believes it is remote that the impact of such matters, other than those discussed below, that are reasonably possible to occur will have a material adverse effect on the Company’s financial position, results of operations or cash flows.
In February 2021, the Permian Basin was impacted by record-low temperatures and a severe winter storm (“Winter Storm Uri”) that resulted in multi-day electrical outages and shortages, pipeline and infrastructure freezes, transportation disruptions, and regulatory actions in Texas, which led to significant increases in gas prices, gathering, processing and transportation fees and electrical rates during this time. As a result, many oil and gas operations, including upstream producers like the Company, as well as gas processors and purchasers, and transportation providers experienced operational disruptions. During this time, the Company was unable to utilize the entire volume of its reserved capacity on pipelines and as a result has made certain force majeure declarations. One third-party transportation provider has filed a lawsuit against the Company claiming compensation for the full amount of the reserved capacity, both utilized and unutilized. The Company has made a payment for the utilized capacity, and filed a separate lawsuit against the transportation provider requesting declaratory relief for the purpose of construing the provisions of the transportation agreement relating to the unutilized capacity. At this time, the Company believes that a loss is reasonably possible in relation to these matters and such amount could range from zero to $7.6 million, and no amount in that range is a better estimate than any other.
89
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 14—Revenues
Revenue from Contracts with Customers
Crude oil, natural gas and NGL sales are recognized at the point control of the product is transferred to the customer and collectability is reasonably assured. Virtually all of the Company’s contract pricing provisions are tied to a market index, with certain adjustments based on, among other factors, transportation costs to an active spot market and quality differentials. As a result, the Company’s realized price of oil, natural gas, and NGLs fluctuates to remain competitive with other available oil, natural gas, and NGLs supplies both globally (in the case of crude oil) and locally.
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
Operating revenues (in thousands): | |||||||||||||||||
Oil sales | $ | $ | $ | ||||||||||||||
Natural gas sales | |||||||||||||||||
NGL sales | |||||||||||||||||
Oil and gas sales | $ | $ | $ | ||||||||||||||
Oil sales
The Company’s crude oil sales contracts are generally structured whereby oil is delivered to the purchaser at a contractually agreed-upon delivery point at which the purchaser takes title of the product. This delivery point is usually at the wellhead or at the inlet of a transportation pipeline. Revenue is recognized when control transfers to the purchaser at the delivery point based on the net price received from the purchaser. Any downstream transportation costs incurred by crude purchasers are reflected as a net reduction to oil sales revenues.
Natural gas and NGL sales
Under the Company’s natural gas processing contracts, liquids rich natural gas is delivered to a midstream gathering and processing entity at the inlet of the gas gathering system. The midstream processing entity gathers and processes the raw gas and then remits proceeds to Centennial for the resulting sales of NGLs, while the Company generally elects to take its residue gas product “in-kind” at the plant tailgate. For these contracts, the Company evaluates when control is transferred and revenue should be recognized. Where the Company has concluded that control transfers at the tailgate of the processing facility, fees incurred prior to transfer of control are presented as gathering, processing and transportation expenses (“GP&T”) within the consolidated statements of operations. Any transportation and fractionation costs incurred subsequent to the point of transfer of control are reflected as a net reduction to natural gas and NGL sales revenues presented in the table above.
Performance obligations
For all commodity products, the Company records revenue in the month production is delivered to the purchaser. Settlement statements for natural gas and NGL sales may not be received for 30 to 90 days after the date production volumes are delivered and for crude oil, generally within 30 days after delivery has occurred. However, payment is unconditional once the performance obligations have been satisfied. At this time, the volume and price can be reasonably estimated and amounts due from customers are accrued in Accounts receivable, net in the consolidated balance sheets. As of December 31, 2021 and December 31, 2020, such receivable balances were $57.3 million and $41.7 million, respectively.
The Company records any differences between its estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. Historically, any identified differences between revenue estimates and actual revenue received have not been significant. For the years ended December 31, 2021 and 2020, revenue recognized in the reporting period related to performance obligations satisfied in prior reporting periods were not material.
90
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Note 15—Leases
At contract inception, the Company determines whether or not an arrangement contains a lease. However, in connection with the implementation of ASC 842, Leases (“ASC 842”), this assessment was made as of the adoption date of ASC 842. Upon determination of a lease, a lease right-of-use (“ROU”) asset and related liability are recorded based on the present value of the future lease payments over the lease term. ROU assets represent the Company’s right to use an underlying asset for the lease term, and lease liabilities represent the obligation to make future lease payments arising from the lease.
The Company has operating leases for drilling rig contracts, office rental agreements, and other wellhead equipment. As of December 31, 2021, these leases have remaining lease terms ranging from one month to ten years , some of which include options to extend the lease term for up to five years , and some of which include options to early terminate. These options are considered in determining the lease term and are included in the present value of future payments that are recorded for leases when the Company is reasonably certain to exercise the option. Leases with an initial term of one year or less are not recorded in the consolidated balance sheets. Additionally, none of the Company’s lease agreements contain any material residual value guarantees or material restrictive covenants.
The present value of future lease payments is determined at the lease commencement date based upon the Company’s incremental borrowing rate. The incremental borrowing rate is calculated using a risk-free interest rate adjusted for the Company’s specific risk and the specific lease term. The table below summarizes the Company’s weighted average discount rate and weighted-average remaining lease term as of the periods presented.
| December 31, 2021 | December 31, 2020 | ||||||||||
| Weighted-average discount rate | % | % | |||||||||
| Weighted-average remaining lease term (years) | |||||||||||
The Company’s drilling rig contracts, office rental agreements, and wellhead equipment agreements contain both lease and non-lease components, which are combined and accounted for as a single lease component.
91
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Variable lease payments are recognized in the period in which they are incurred and include operating expenses related to the office rental agreements and expenses incurred on the drilling rig contracts in excess of the contractual rate. Expenses related to short-term leases are recognized on a straight-line basis over the lease term as either expenses to the consolidated statements of operations or capitalized to the consolidated balance sheets. The following table presents the components of the Company’s lease expenses for the periods presented.
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Lease costs | |||||||||||
Operating lease cost | $ | $ | |||||||||
Variable lease cost | |||||||||||
| Short-term lease cost | |||||||||||
Total Lease Cost | $ | $ | |||||||||
| Year Ended December 31, | |||||||||||
| (in thousands) | 2021 | 2020 | |||||||||
| Operating lease liability payments: | |||||||||||
| Net cash used in operating activities | $ | $ | |||||||||
| Net cash used in investing activities | $ | $ | |||||||||
| Right-of-use assets recognized (derecognized) with offsetting operating lease liabilities | $ | $ | ( | ||||||||
Maturities of the Company’s long-term operating lease liabilities by fiscal year as of December 31, 2021 are as follows:
| (in thousands) | Total(2) | |||||||
| 2022 | ||||||||
| 2023 | ||||||||
| 2024 | ||||||||
| 2025 | ||||||||
| 2026 | ||||||||
| 2027 and thereafter | ||||||||
| Total lease payments | ||||||||
| Less: imputed interest | ( | |||||||
Present value of lease liabilities(1) | $ | |||||||
(1) This amount is included in current and noncurrent liabilities in the line item Operating lease liabilities in the consolidated balance sheets as of December 31, 2021.
Note 16—Subsequent events
Credit Facility
On February 18, 2022, CRP closed on a new five-year revolving credit facility replacing the previous Credit Agreement that was set to mature on May 4, 2023. The new credit facility has elected commitments of $750 million, a borrowing base of $1.15 billion and will mature in February 2027. Refer to Liquidity and Capital Resources under Part II, Item 7 of this Annual Report for additional information on the terms of the new credit agreement.
Stock Repurchase Program
In February 2022, the Company’s Board of Directors authorized a stock repurchase program to acquire up to $350 million of the Company’s outstanding Common Stock (the “Repurchase Program”), which is approved through April 1, 2024. The Company intends to use the Repurchase Program to reduce its shares of Common Stock outstanding and plans to fund these repurchases with cash on hand and cash flows from operations. Repurchases may be made from time to time in the open-market or via
92
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Supplemental Information About Oil & Natural Gas Producing Activities (Unaudited)
Capitalized Costs
The aggregate amounts of costs capitalized for oil and gas exploration and development activities and the related amounts of accumulated depreciation, depletion and amortization are shown below:
| (in thousands) | December 31, 2021 | December 31, 2020 | |||||||||
| Proved properties | $ | 4,623,726 | $ | 4,395,473 | |||||||
| Unproved properties | 1,040,386 | 1,209,205 | |||||||||
| Total proved and unproved properties | 5,664,112 | 5,604,678 | |||||||||
| Accumulated depreciation, depletion and amortization | (1,989,489) | (1,877,832) | |||||||||
| Net capitalized costs | $ | 3,674,623 | $ | 3,726,846 | |||||||
Costs Incurred for Oil and Natural Gas Producing Activities
The costs incurred in the Company’s oil and gas production, exploration, and development activities are displayed in the table below and include costs whether capitalized or expensed as well as revisions and additions to the estimated future asset retirement obligations.
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Acquisition costs: | |||||||||||||||||
| Proved properties | $ | 1,988 | $ | 1,384 | $ | 3,437 | |||||||||||
| Unproved properties | 4,522 | 4,768 | 81,602 | ||||||||||||||
Advances for unproved properties(1) | — | 2,312 | 18,345 | ||||||||||||||
Development costs(2) | 303,938 | 284,006 | 875,911 | ||||||||||||||
Exploration costs(3) | 5,718 | 16,439 | 11,390 | ||||||||||||||
| Total | $ | 316,166 | $ | 308,909 | $ | 990,685 | |||||||||||
(1) Advances for unproved properties represent amounts paid to a third-party broker to acquire approximately 24,000 net leasehold acres on the Company’s behalf in the Permian Basin. This prepaid amount was included in the Other noncurrent assets line item on the consolidated balance sheet; however, it was impaired during the year ended December 31, 2020. Refer to the Management Discussion and Analysis of Financial Condition and Results of Operations under Part II, Item 7 of this Annual Report for further discussion.
(2) Includes the cost of drilling development wells and associated facilities for which construction was completed during the period. Costs associated with wells and facilities that are in progress or awaiting completion at year-end are not included and were $60.6 million, $45.3 million and $86.8 million as of the years ended December 31, 2021, 2020 and 2019, respectively.
(3) Includes all exploratory expenses, including dry hole costs. Does not include other operating expenses.
93
CENTENNIAL RESOURCE DEVELOPMENT, INC.
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS (Continued)
Estimated Quantities of Proved Oil and Gas Reserves
The reserve estimates presented below and included herein conform to the definitions prescribed by the SEC. The Company retained Netherland, Sewell & Associates, Inc., an independent petroleum engineering firm, to prepare the estimates of all of its proved reserves as of December 31, 2021, 2020 and 2019 and their related pre-tax future net cash flows. The individuals performing reserves estimates possess professional qualifications and demonstrate competency in reserves estimation and evaluation. The estimates of proved reserves are inherently imprecise and are continually subject to revision based on production history, results of additional exploration and development, price changes and other factors.
Reserve estimates are based on an unweighted arithmetic average of commodity prices during the 12-month period, using the closing prices on the first day of each month, as defined by the SEC.
As of December 31, 2021, all of the Company’s oil and gas reserves are attributable to properties within the United States. The table below presents a summary of changes in quantities of proved oil and gas reserves in the Company’s estimated proved reserves:
| Crude Oil (MBbls) | Natural Gas (MMcf) | Natural Gas Liquids (MBbls) | Total (MBoe)(1) | ||||||||||||||||||||
| Total proved reserves: | |||||||||||||||||||||||
| Balance - December 31, 2018 | 142,766 | 402,852 | 51,918 | 261,826 | |||||||||||||||||||
| Extensions and discoveries | 33,093 | 76,820 | 10,527 | 56,424 | |||||||||||||||||||
| Revisions to previous estimates | (9,845) | 64,558 | 10,047 | 10,959 | |||||||||||||||||||
| Purchases of reserves in place | 9 | 209 | 30 | 74 | |||||||||||||||||||
| Divestitures of reserves in place | (282) | (306) | (46) | (378) | |||||||||||||||||||
| Production | (15,582) | (41,703) | (5,234) | (27,766) | |||||||||||||||||||
| Balance - December 31, 2019 | 150,159 | 502,430 | 67,242 | 301,139 | |||||||||||||||||||
| Extensions and discoveries | 33,220 | 73,669 | 9,877 | 55,375 | |||||||||||||||||||
| Revisions to previous estimates | (19,680) | (7,010) | (12,184) | (33,031) | |||||||||||||||||||
| Production | (13,207) | (41,302) | (4,490) | (24,581) | |||||||||||||||||||
| Balance - December 31, 2020 | 150,492 | 527,787 | 60,445 | 298,902 | |||||||||||||||||||
| Extensions and discoveries | 19,405 | 55,820 | 6,242 | 34,950 | |||||||||||||||||||
| Revisions to previous estimates | (1,948) | 40,697 | (6,703) | (1,868) | |||||||||||||||||||
| Divestitures of reserves in place | (2,795) | (6,558) | (649) | (4,537) | |||||||||||||||||||
| Production | (11,701) | (40,741) | (3,752) | (22,243) | |||||||||||||||||||
| Balance - December 31, 2021 | 153,453 | 577,005 | 55,583 | 305,204 | |||||||||||||||||||
| Proved developed reserves: | |||||||||||||||||||||||
| December 31, 2019 | 74,842 | 237,791 | 32,743 | 147,216 | |||||||||||||||||||
| December 31, 2020 | 70,716 | 279,556 | 31,672 | 148,981 | |||||||||||||||||||
| December 31, 2021 | 77,973 | 326,223 | 30,318 | 162,662 | |||||||||||||||||||
| Proved undeveloped reserves: | |||||||||||||||||||||||
| December 31, 2019 | 75,317 | 264,639 | 34,499 | 153,923 | |||||||||||||||||||
| December 31, 2020 | 79,776 | 248,231 | 28,773 | 149,921 | |||||||||||||||||||
| December 31, 2021 | 75,480 | 250,782 | 25,265 | 142,542 | |||||||||||||||||||
(1) Calculated by converting natural gas to oil equivalent barrels at a ratio of six Mcf of natural gas to one Boe.
94
Notable changes in proved reserves for the year ended December 31, 2021 included the following:
•Extensions and discoveries. In 2021, 35.0 MMBoe of proved reserves were added through extensions and discoveries and include: i) 30.0 MMBoe for new proved undeveloped (“PUD”) locations; and ii) 5.0 MMBoe for unproved locations that were successfully converted to new proved developed (“PDP”) wells during the period. These additions resulted from the Company’s 2021 drilling program, which added locations primarily in the Bone Spring Sand formations on the Company’s New Mexico acreage and also on the Company’s Texas position in the Wolfcamp C formation.
•Revisions to previous estimates. In 2021, total revisions to previous estimates reduced proved reserves by a net 1.9 MMBoe. Aggregate downward revisions in 2021 were 25.6 MMBoe and primarily related to 21.9 MMBoe of negative revisions associated with PUD locations that were either reclassified to unproved reserves or removed due to changes in the Company’s active development program. The remainder of the downward revisions were associated with timing, performance, and operating cost revisions. These downward revisions were mostly offset by positive revisions of 23.7 MMBoe related primarily to upward pricing adjustments associated with higher average commodity prices for the year ended December 31, 2021.
•Divestitures of reserves in place. In 2021, 4.5 MMBoe of reserves in place were removed following the divestiture of non-core acreage discussed further in Note 2—Property Divestitures.
Notable changes in proved reserves for the year ended December 31, 2020 included the following:
•Extensions and discoveries. In 2020, 55.4 MMBoe of proved reserves were added through extensions and discoveries and include: i) 52.1 MMBoe for new PUD locations; and ii) 3.3 MMBoe for unproved locations that were successfully converted to new PDP) wells during the period. These additions resulted from the Company’s 2020 drilling program, which added locations primarily in the 2nd and 3rd Bone Spring formations on the Company’s New Mexico acreage and also on the Company’s Texas position in the Wolfcamp C and 3rd Bone Spring formations.
•Revisions to previous estimates. In 2020, total revisions to previous estimates reduced proved reserves by a net amount of 33.0 MMBoe. Aggregate downward revisions of 133.4 MMBoe for 2020 consisted of (i) 103.7 MMBoe of downward pricing adjustments and (ii) 29.4 MMBoe of negative revisions associated with PUD locations that were either reclassified to unproved reserves or removed due to changes in the Company’s active development program. These downward revisions were partially offset by aggregate upward revisions of 100.4 MMBoe that were primarily related to reductions in the Company’s operating costs, which extended the lives and increased total reserves for PDP and PUD locations, as well as reductions in per-well capital expenditures that elevated economics for certain PUD locations.
Notable changes in proved reserves for the year ended December 31, 2019 included the following:
•Extensions and discoveries. In 2019, 56.4 MMBoe of proved reserves were added through extensions and discoveries and include: i) 30.5 MMBoe for new PUD locations; and ii) 25.9 MMBoe for unproved locations that were successfully converted to new PDP wells during the period. These additions resulted from the Company’s effective drilling program throughout the year, which added locations primarily in the Upper Wolfcamp A formation in the Company’s Texas position and also in the 2nd Bone Spring formations in the Company’s New Mexico acreage.
•Revisions to previous estimates. In 2019, revisions to previous estimates of 11.0 MMBoe consisted of 27.5 MMBoe of upward revisions primarily related to well performance revisions to reflect higher gas and NGL yields on older wells, which in turn increased total EURs for most proved developed and PUD locations. These positive revisions were partially offset by 16.5 MMBoe of negative revisions, of which 10.1 MMBoe related to downward pricing adjustments due to lower average commodity prices for oil, gas and NGLs for the year ended December 31, 2019. The remainder of the downward revisions related to PUD locations that were reclassified to unproven reserves due to them no longer being a part of the Company’s active development program.
Standardized Measure of Discounted Future Net Cash Flows
The standardized measure of discounted future net cash flows (the “Standardized Measure”) relating to proved oil and gas reserves has been prepared in accordance with FASB ASC Topic 932, Extractive Activities - Oil and Gas (“ASC 932”). Future cash inflows as of December 31, 2021, 2020 and 2019 have been computed by applying average fiscal year prices (calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month periods ended December 31, 2021, 2020 and 2019, respectively) to estimated future production. Future production and development costs are computed by estimating the expenditures to be incurred in developing and producing the proved oil and gas reserves, based on year-end costs and assuming the continuation of existing economic conditions. The Standardized Measure also includes costs for future dismantlement, abandonment and rehabilitation obligations.
95
Future income tax expenses are calculated by applying appropriate year-end tax rates to future pretax net cash flows relating to proved oil and natural gas reserves, less the tax basis of properties involved. Future income tax expenses give effect to permanent differences, tax credits and loss carryforwards relating to the proved oil and natural gas reserves.
Future net cash flows are discounted at a rate of 10% annually to derive the Standardized Measure. This calculation does not necessarily result in an estimate of the fair value of the Company’s oil and gas properties.
The following table presents the Company’s Standardized Measure of discounted future net cash flows:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Future cash inflows | $ | 13,224,260 | $ | 6,700,654 | $ | 9,616,702 | |||||||||||
| Future development costs | (984,827) | (974,163) | (1,410,494) | ||||||||||||||
| Future production costs | (4,404,841) | (3,135,089) | (3,943,766) | ||||||||||||||
| Future income tax expenses | (1,162,657) | (25,487) | (391,168) | ||||||||||||||
| Future net cash flows | 6,671,935 | 2,565,915 | 3,871,274 | ||||||||||||||
| 10% discount to reflect timing of cash flows | (3,275,615) | (1,381,240) | (1,808,902) | ||||||||||||||
| Standardized measure of discounted future net cash flows | $ | 3,396,320 | $ | 1,184,675 | $ | 2,062,372 | |||||||||||
The following summarizes the principal sources of change in the Standardized Measure of discounted future net cash flows and such changes have been computed in accordance with ASC 932:
| Year Ended December 31, | |||||||||||||||||
| (in thousands) | 2021 | 2020 | 2019 | ||||||||||||||
| Standardized measure of discounted future net cash flows, beginning of period | $ | 1,184,675 | $ | 2,062,372 | $ | 2,479,851 | |||||||||||
Sales of oil, natural gas and NGLs, net of production costs | (770,437) | (360,448) | (662,319) | ||||||||||||||
| Purchase of minerals in place | — | — | 154 | ||||||||||||||
Divestiture of minerals in place | (34,334) | — | (5,593) | ||||||||||||||
| Extensions and discoveries, net of future development costs | 445,256 | 177,325 | 526,083 | ||||||||||||||
| Previously estimated development costs incurred during the period | 216,526 | 167,135 | 380,376 | ||||||||||||||
| Net change in prices and production costs | 2,859,463 | (1,428,068) | (1,395,537) | ||||||||||||||
| Change in estimated future development costs | (3,747) | 463,286 | 15,056 | ||||||||||||||
| Revisions of previous quantity estimates | (29,946) | (236,917) | 47,226 | ||||||||||||||
| Accretion of discount | 118,914 | 219,789 | 297,946 | ||||||||||||||
| Net change in income taxes | (476,681) | 131,054 | 364,089 | ||||||||||||||
| Net change in timing of production and other | (113,369) | (10,853) | 15,040 | ||||||||||||||
| Standardized measure of discounted future net cash flows, end of period | $ | 3,396,320 | $ | 1,184,675 | $ | 2,062,372 | |||||||||||
Future net revenues included in the Standardized Measure relating to proved oil and natural gas reserves incorporate weighted average sales prices (inclusive of adjustments for transportation, quality and basis differentials) for each of the periods indicated below as follows:
| Year Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| Oil (per Bbl) | $ | 61.77 | $ | 35.89 | $ | 52.62 | |||||||||||
| Gas (per Mcf) | 3.23 | 0.97 | 0.87 | ||||||||||||||
| NGLs (per Bbl) | 33.89 | 13.00 | 18.99 | ||||||||||||||
96
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE
None.
ITEM 9A. CONTROLS AND PROCEDURES
Evaluation of Disclosure Control and Procedures
In accordance with Exchange Act Rules 13a-15 and 15d-15, the Company has evaluated, under the supervision and with the participation of management, including the principal executive officer and principal financial officer, the effectiveness of the design and operation of disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act) as of December 31, 2021. Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed in reports that the Company files under the Exchange Act is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate, to allow timely decisions regarding required disclosure and is recorded, processed, summarized and reported within the time periods specified in the rules and forms of the SEC. Based upon that evaluation, the principal executive officer and principal financial officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2021 at the reasonable assurance level.
Management’s Annual Report on Internal Control Over Financial Reporting
Management, including the principal executive officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of the consolidated financial statements for external purposes in accordance with GAAP.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Management assessed the effectiveness of the Company’s internal control over financial reporting as of December 31, 2021, using the criteria in Internal Control-Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation, management believes that the Company’s internal control over financial reporting was effective as of December 31, 2021.
This Annual Report includes an attestation report of KPMG LLP, the Company’s independent registered public accounting firm, on the Company’s internal control over financial reporting as of December 31, 2021, which is included in this Annual Report.
Changes in Internal Control over Financial Reporting
There were no changes in the system of internal control over financial reporting (as defined in Rule 13a-15(f) and Rule 15d-15(f) under the Exchange Act) during the quarter ended December 31, 2021 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
ITEM 9B. OTHER INFORMATION
None.
ITEM 9C. DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS.
None.
97
PART III
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of stockholders and is incorporated herein by reference.
ITEM 11. EXECUTIVE COMPENSATION
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of stockholders and is incorporated herein by reference.
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of stockholders and is incorporated herein by reference.
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of stockholders and is incorporated herein by reference.
ITEM 14. PRINCIPAL ACCOUNTANT FEES AND SERVICES
Our independent registered public accounting firm is KPMG LLP , Denver, Colorado , Auditor Firm ID: 185 .
The information required in response to this item will be set forth in our definitive proxy statement for the 2022 annual meeting of stockholders and is incorporated herein by reference.
98
PART IV
ITEM 15. EXHIBITS AND FINANCIAL STATEMENTS SCHEDULES
| Page | ||||||||
| (a)(1) | The following financial statements are included in Item 8. Financial Statements and Supplementary Data in this Annual Report: | |||||||
| (2) | Financial statement schedules—None | |||||||
| (3) | Exhibits: | |||||||
Exhibit Number | Description of Exhibits | |||||||
| 2.1 | ||||||||
| 2.2 | ||||||||
| 2.3 | ||||||||
| 3.1 | ||||||||
| 3.2 | ||||||||
| 3.3 | ||||||||
| 3.4 | ||||||||
| 3.5 | ||||||||
| 3.6 | ||||||||
| 4.1 | ||||||||
| 4.2 | ||||||||
| 4.3 | ||||||||
| 4.4 | ||||||||
| 4.5 | ||||||||
| 4.6 | ||||||||
| 4.7 | ||||||||
99
| 4.8 | ||||||||
| 10.1 | ||||||||
| 10.2 | ||||||||
| 10.3 | ||||||||
| 10.4 | ||||||||
| 10.5 | ||||||||
| 10.6# | ||||||||
| 10.7# | ||||||||
| 10.8# | ||||||||
| 10.9# | ||||||||
| 10.10# | ||||||||
| 10.11# | ||||||||
| 10.12# | ||||||||
| 10.13# | ||||||||
| 10.14# | ||||||||
| 10.15# | ||||||||
| 10.16# | ||||||||
| 10.17 | ||||||||
| 10.18 | ||||||||
| 10.19 | ||||||||
| 10.20# | ||||||||
| 10.21 | ||||||||
| 21.1* | ||||||||
| 23.1* | ||||||||
| 23.2* | ||||||||
100
| 31.1* | ||||||||
| 31.2* | ||||||||
| 32.1* | ||||||||
| 32.2* | ||||||||
| 99.1 | ||||||||
| 99.2 | ||||||||
| 99.3* | ||||||||
| 101.INS* | Inline XBRL Instance Document - The instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||
| 101.SCH* | Inline XBRL Taxonomy Extension Schema Document. | |||||||
| 101.CAL* | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||
| 101.DEF* | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |||||||
| 101.LAB* | Inline XBRL Taxonomy Extension Label Linkbase Document. | |||||||
| 101.PRE* | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||
* Filed herewith.
# Management contract or compensatory plan or agreement.
ITEM 16. FORM 10-K SUMMARY
None.
101
SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereto duly authorized.
| CENTENNIAL RESOURCE DEVELOPMENT, INC. | ||||||||
| By: | /s/ GEORGE S. GLYPHIS | |||||||
George S. Glyphis Executive Vice President and Chief Financial Officer | ||||||||
Pursuant to the requirements of the Securities Act of 1934, this registration statement has been signed by the following persons in the capacities and on the dates indicated.
| Signature | Title | Date | ||||||||||||
| /s/ SEAN R. SMITH | ||||||||||||||
| Sean R. Smith | Chief Executive Officer and Director (Principal Executive Officer) | February 24, 2022 | ||||||||||||
| /s/ GEORGE S. GLYPHIS | ||||||||||||||
| George S. Glyphis | Executive Vice President and Chief Financial Officer | February 24, 2022 | ||||||||||||
| /s/ BRENT P. JENSEN | ||||||||||||||
| Brent P. Jensen | Senior Vice President and Chief Accounting Officer (Principal Accounting Officer) | February 24, 2022 | ||||||||||||
| /s/ STEVEN J. SHAPIRO | ||||||||||||||
| Steven J. Shapiro | Chairman | February 24, 2022 | ||||||||||||
| /s/ MAIRE A. BALDWIN | ||||||||||||||
| Maire A. Baldwin | Director | February 24, 2022 | ||||||||||||
| /s/ MATTHEW G. HYDE | ||||||||||||||
| Matthew G. Hyde | Director | February 24, 2022 | ||||||||||||
| /s/ PIERRE F. LAPEYRE, JR. | ||||||||||||||
| Pierre F. Lapeyre, Jr. | Director | February 24, 2022 | ||||||||||||
| /s/ DAVID M. LEUSCHEN | ||||||||||||||
| David M. Leuschen | Director | February 24, 2022 | ||||||||||||
| /s/ VIDISHA PRASAD | ||||||||||||||
| Vidisha Prasad | Director | February 24, 2022 | ||||||||||||
| /s/ JEFFREY H. TEPPER | ||||||||||||||
| Jeffrey H. Tepper | Director | February 24, 2022 | ||||||||||||
| /s/ ROBERT M. TICHIO | ||||||||||||||
| Robert M. Tichio | Director | February 24, 2022 | ||||||||||||
102
