The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s saleour sales of oil, natural gas and NGLs for the periods indicated. For further details, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations - Results of Operations”.
|
| | | | | | | | | |
| | Years Ended December 31, |
| | 2019 (1) | | 2018 | | 2017 |
Total production (2) | | |
Oil (MBbls) | | 11,665 |
| | 9,443 |
| | 6,557 |
|
Natural gas (MMcf) | | 19,718 |
| | 15,447 |
| | 10,896 |
|
NGLs (MBbls) | | 135 |
| | — |
| | — |
|
Total barrels of oil equivalent (MBoe) | | 15,086 |
| | 12,018 |
| | 8,373 |
|
| | | | | | |
Daily production volumes by product (2) | | | | | | |
Oil (Bbls/d) | | 31,957 |
| | 25,871 |
| | 17,964 |
|
Natural gas (Mcf/d) | | 54,021 |
| | 42,321 |
| | 29,852 |
|
NGLs (Bbls/d) | | 370 |
| | — |
| | — |
|
Total barrels of oil equivalent (Boe/d) | | 41,331 |
| | 32,926 |
| | 22,940 |
|
| | | | | | |
Daily production volumes by region (2) | | | | | | |
Permian Basin | | 40,287 |
| | 32,926 |
| | 22,940 |
|
Eagle Ford Shale | | 1,044 |
| | — |
| | — |
|
Total barrels of oil equivalent (Boe/d) | | 41,331 |
| | 32,926 |
| | 22,940 |
|
|
| | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 (1) | | 2018 | | 2017 |
Revenues (in thousands) | | | | | | |
Oil | |
| $633,107 |
| |
| $530,898 |
| |
| $322,374 |
|
Natural gas | | 36,390 |
| | 56,726 |
| | 44,100 |
|
NGLs | | 2,075 |
| | — |
| | — |
|
Total revenues | |
| $671,572 |
| |
| $587,624 |
| |
| $366,474 |
|
| | | | | | |
Operating costs (in thousands) | | | | | | |
Lease operating expense | |
| $91,827 |
| |
| $69,180 |
| |
| $49,907 |
|
Production taxes | | 42,651 |
| | 35,755 |
| | 22,396 |
|
Total operating costs | |
| $134,478 |
| |
| $104,935 |
| |
| $72,303 |
|
| | | | | | |
Average realized sales price (excluding impact of settled derivatives) | | | | | | |
Oil (per Bbl) | |
| $54.27 |
| |
| $56.22 |
| |
| $49.16 |
|
Natural gas (per Mcf) | | 1.85 |
| | 3.67 |
| | 4.05 |
|
NGL (per Bbl) | | 15.37 |
| | — |
| | — |
|
Total (per Boe) | |
| $44.52 |
| |
| $48.90 |
| |
| $43.77 |
|
| | | | | | |
Average realized sales price (including impact of settled derivatives) | | | | | | |
Oil (per Bbl) | |
| $53.31 |
| |
| $53.31 |
| |
| $47.78 |
|
Natural gas (per Mcf) | | 2.22 |
| | 3.69 |
| | 4.10 |
|
NGL (per Bbl) | | 15.37 |
| | — |
| | — |
|
Total (per Boe) | |
| $44.27 |
| |
| $46.63 |
| |
| $42.76 |
|
| | | | | | |
Operating costs per Boe | | | | | | |
Lease operating expense | |
| $6.09 |
| |
| $5.76 |
| |
| $5.96 |
|
Production taxes | | 2.83 |
| | 2.98 |
| | 2.67 |
|
Total (per Boe) | |
| $8.92 |
| |
| $8.74 |
| |
| $8.63 |
|
| |
(1) | Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. |
| |
(2) | The production associated with reserves acquired in the Carrizo Acquisition is presented on a three-stream basis and include NGLs, whereas, all other production volumes are on a two-stream basis. |
Major Customers
Our production is sold generally on month-to-month contracts at prevailing market prices. The following table presents customers that represented 10% or more of our total revenues for at least one of the periods presented:
|
| | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Rio Energy International, Inc. | | 26% | | 28% | | 17% |
Enterprise Crude Oil, LLC | | 19% | | 14% | | 18% |
Plains Marketing, L.P. | | 15% | | 21% | | 29% |
Shell Trading Company | | 10% | | * | | * |
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
Shell Trading Company | | 20% | | 31% | | 10% |
Trafigura Trading, LLC | | 15 | | * | | * |
Occidental Energy Marketing, Inc. | | 13 | | * | | * |
Valero Marketing and Supply Company | | 13 | | 23 | | * |
Rio Energy International, Inc. | | * | | * | | 26 |
Enterprise Crude Oil, LLC | | * | | * | | 19 |
Plains Marketing, L.P. | | * | | * | | 15 |
* - Less than 10% for the respective year.years.
Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security.
Leasehold Acreage
The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2019.2021. Developed acreage refers to acreage on which wells have been completed to a point that would permit production of oil and gas in commercial quantities. Undeveloped acreage refers to acreage on which wells have not been drilled or completed to a point that would permit production of oil and gas in commercial quantities whether or not the acreage contains proved reserves.
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Developed Acreage | | Undeveloped Acreage | | Total Acreage | | Net Undeveloped Acreage Expiring |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | | 2020 | | 2021 | | 2022 |
Permian Basin (1) | | 137,786 |
| | 97,352 |
| | 36,136 |
| | 19,432 |
| | 173,922 |
| | 116,784 |
| | 13,765 |
| | 1,903 |
| | 981 |
|
Eagle Ford Shale (2) | | 75,864 |
| | 64,146 |
| | 14,696 |
| | 12,088 |
| | 90,560 |
| | 76,234 |
| | 1,357 |
| | — |
| | 300 |
|
Other (3) | | 2,123 |
| | 174 |
| | 79,615 |
| | 57,070 |
| | 81,738 |
| | 57,244 |
| | — |
| | 1,234 |
| | 48,504 |
|
Total | | 215,773 |
| | 161,672 |
| | 130,447 |
| | 88,590 |
| | 346,220 |
| | 250,262 |
| | 15,122 |
| | 3,137 |
| | 49,785 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Developed Acreage | | Undeveloped Acreage | | Total Acreage | | Net Undeveloped Acreage Expiring |
| | Gross | | Net | | Gross | | Net | | Gross | | Net | | 2022 | | 2023 | | 2024 |
Permian (1) | | 151,368 | | | 128,777 | | | 9,555 | | | 6,363 | | | 160,923 | | | 135,140 | | | 2,439 | | | 157 | | | 256 | |
Eagle Ford (2) | | 63,431 | | | 52,553 | | | 2,553 | | | 445 | | | 65,984 | | | 52,998 | | | 20 | | | — | | | — | |
Other (3) | | 2,080 | | | 122 | | | 71,059 | | | 55,837 | | | 73,139 | | | 55,959 | | | 48,504 | | | 3,398 | | | 2,994 | |
Total | | 216,879 | | | 181,452 | | | 83,167 | | | 62,645 | | | 300,046 | | | 244,097 | | | 50,963 | | | 3,555 | | | 3,250 | |
| |
(1) | Approximately 16%, 81% and 39% of the acreage expiring in 2020, 2021 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. The acreage expiring in 2020 is primarily in our Alpine High area, which was acquired as part of the Carrizo Acquisition, where, along with the other remaining acreage, we have no current development plans. |
| |
(2) | Approximately 87% and 100% of the acreage expiring in 2020 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. We have no current development plans for the remaining expiring acreage as of December 31, 2019. |
| |
(3) | Other includes non-core acreage principally located in Texas. We have no current development plans with this acreage as of December 31, 2019. |
(1)Based on our current plans, approximately 67%, 76% and 63% of the acreage expiring in 2022, 2023 and 2024, respectively, will be developed prior to expiration or extended by lease extension payments.
(2)Based on our current plans, approximately 100% of the acreage expiring in 2022 will be developed prior to expiration or extended by lease extension payments.
(3)Consists of non-core acreage principally located in Texas. We have no current development plans and no proved undeveloped reserves associated with this acreage as of December 31, 2021.
Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that can beis generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2020, 20212022, 2023 and 20222024 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material expirations.loss of acreage or depths. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans.
The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company.
Human Capital
Callon employs a talented workforce that is integral to our success, and we are committed to the safety, health, and development of each team member. The Callon culture is defined by our values of responsibility, integrity, drive, respect and excellence. These core values are a reflection of our ideals as individuals and direct our actions as a company.
Callon’s key human capital management objectives are to attract, retain and develop talent to deliver on our strategy. Due to the technical nature of our business, our success depends on a highly skilled workforce in multiple disciplines including engineering, geology, operations, land, information technology and various other corporate functions. To support the attraction and retention of top talent, our human resources programs are designed to keep our employees safe and healthy, engage employees with an inclusive
workplace, reward and support employees through competitive pay and benefit programs, and develop talent to support personal growth and prepare employees for high impact roles and leadership positions.
As of December 31, 2021, Callon had 322 permanent, full-time employees. None of our employees are currently represented by a union, and we believe that we have good relations with our employees.
We focus on the following in supporting our human capital:
•Inclusion and Diversity - We believe that diversity of backgrounds and perspectives contributes to an innovative workforce and an enriching environment for our employees. Callon is firmly committed to fostering an inclusive, respectful environment and providing equal opportunity to all qualified persons in our hiring, development, and compensation practices. As of December 31, 2021, approximately 37% of our permanent, full-time employees were minorities, 21% were female, and 35% of above-field employees were female. We continually seek to expand diversity in our workforce, and in 2021, 37% of our newly hired employees represented minorities and 40% were female.
•Health and Safety - Protecting our employees, contractors and communities is a core value at Callon and our top priority. Our Operations Management System (“OMS”) establishes clear expectations for operating safely and responsibly throughout the lifecycle of our business. We identify and mitigate safety risks and integrate a culture of safety by operating according to OMS standards, processes, and procedures. Additionally, we share our Safety and Environmental Policy with all employees and contractors which includes each individual’s authorization and responsibility to stop work on any activity without the threat or fear of job reprisal. To reinforce accountability for safety results, our Board of Directors included safety performance as a factor in our 2021 annual bonus program.
•Employee Compensation, Benefits and Wellness - Our compensation and benefits programs provide a package designed to attract, retain and motivate employees. In addition to competitive base salaries, we provide a variety of short-term and long-term incentive compensation programs to reward performance relative to key financial, operational, and ESG metrics. Callon invests in the health and well-being of our employees and their families by paying 100% of the premiums for our health care plan, which includes telemedicine and an Employee Assistance Program. We also offer comprehensive benefit options including a retirement savings plan, life and disability insurance, health savings accounts, flexible spending accounts, and a charitable matching program.
•Employee Development - We believe that ongoing investment in the development of our team members is key to our future success, as well as the retention of our employees. Callon fosters an entrepreneurial workplace where employees can expand their skill sets and experience by direct engagement and collaboration with leaders at all levels. Additionally, we offer tuition assistance and access to various training programs, including a monthly in-house leadership development program in 2021. Our leaders support all of our employees in reaching their personal goals through ongoing feedback and development conversations.
For additional information, please see our Sustainability Report published on our company website (www.callon.com).
Other
Industry Segment and Geographic Information
For segment reporting purposes, the CompanyCallon considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’sour assets are located within the United States and all operations are located within Texas. All of the production revenues generated from operations are contracted and sold to customers located in the United States.
Title to Properties
The Company believesWe believe that the title to itsour oil and natural gas properties is good and defensible in accordance with standards generally accepted in the oil and gas industry, subject to such exceptions which, in our opinion, are not so material as to detract substantially from the use or value of such properties. The Company’sNevertheless, we can be involved in title disputes from time to time which may result in litigation. Our properties are potentially subject to one or more of the following:
royaltiesburdens such as royalty, overriding royalty, working and other burdens and obligations, express or implied, under oil and natural gas leases;
overriding royalties and other burdens created by us or our predecessors in title;
a variety of contractual obligations (including, in some cases, development obligations) arising under operating agreements; farm-out agreements, production sales contracts and other agreements that may affect the properties or their titles;
back-ins and reversionaryoutstanding interests existing under purchase agreements and leasehold assignments;
liens that arisecustomary in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;
pooling, unitization and communitization agreements, declarations and orders; and
easements, restrictions, rights-of-way and other matters that commonly affect property.
industry. To the extent that such burdens and obligations affect the Company’sour rights to production revenues, these characteristics have been taken into account in calculating Callon’sour net revenue interests and in estimating the size and value of itsour estimated proved reserves. The Company believesWe believe that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon.
Seasonality of Business
Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis.
Competition
The Company operatesWe operate in the oil and natural gas industry, which is highly competitive. The Company’sOur business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’sour ability to acquire additional properties and resources necessary to develop assets. In higher commodity pricing environments, competition also exists in the form of contracting for drilling, pumping, and workover equipment, and securing skilled personnel to both develop and operate existing assets. Many of the competitors mentioned above may be able to pay for more sought-after properties or access equipment, infrastructure, or personnel. The industry also experiences, from time to time, shortages in resources such as the availability of drilling and workover rigs, other equipment, pipes and materials, infrastructures, and skilled personnel, all of which can delay development, exploration, and workover activities as well as result in significant cost increases.
Insurance
In accordance with industry practice, the Company maintainswe maintain insurance against some but not all, of the operating risks to which itsour business is exposed. While not all inclusive, the Company’sour insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for itsour exploration and production operations.
The Company entersWe enter into master service agreements with itsour third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Companyus for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Companywe generally agreesagree to indemnify each third-party contractor against claims made by our employees of the Company and the Company’sour other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluatesWe reevaluate the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured based on our risk analysis, no assurance can be given that the Companywe will be able to maintain insurance in the future at rates that it considerswe consider reasonable. In such circumstances, the Companywe may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.
Corporate Offices
The Company’sOur headquarters are located in Houston, Texas, in a building with office space leased by the Company.that we lease. We own office buildings in Natchez, Mississippi and Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures.
Employees
With the addition of employees from the Carrizo Acquisition that closed on December 20, 2019, Callon had 475 employees as of December 31, 2019. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.
Regulations
General. Oil and natural gas operations such as ours are subject to various types of legislation, regulation and other legal requirements enacted by governmental authorities.authorities at the federal, state, and local levels. Some of these requirements carry substantial penalties for failure to comply. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.revision, and various proposals and proceedings that might affect the industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. We cannot predict what effect such proposals or proceedings may have on our operations, capital expenditures, earnings or competitive position.
Exploration and Production. Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:
•the location and spacing of wells;
•the method of drilling and completing and operating wells;
•the rate and method of production;
•the surface use and restoration of properties upon which wells are drilled and other exploration activities;
•notice to surface owners and other third parties;
•the venting or flaring of natural gas;
•the plugging and abandoning of wells;
•the discharge of contaminants into water and the emission of contaminants into air;
•the disposal of fluids used or other wastes obtained in connection with operations;
•the marketing, transportation and reporting of production; and
•the valuation and payment of royalties.
Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.
Various proposals and proceedings that might affect the petroleum industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and state administrative agencies and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, operations, earnings or competitive position.
Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection.the protection of the environment and natural resources. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent, monitor for or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace.
Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent
requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA was required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.
Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes strict, joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed of or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.
Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event
contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.
We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.
Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers.Engineers (the “Corps”). The EPA and the Corps issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which was repealednever took effect before being replaced by the Navigable Waters Protection Rule (the “NWPR”) in December 2019. A coalition of states and cities, environmental groups, and agricultural groups challenged the NWPR, which was vacated by a federal district court in August 2021. The EPA on October 22, 2019. On January 23, 2020,is undergoing a rulemaking process to redefine the EPA and the U.S. Army Corpsdefinition of Engineers issued a final rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to
federal regulation. The rule is the subject of various legal challenges, creating uncertainty regarding federal jurisdiction over waters of the United States.States; in the interim, the EPA is utilizing the pre-2015 definition.
The EPA has also adopted regulations requiring certain oil and natural gas exploration and production facilities to obtain individual permits or coverage under general permits for storm water discharges. Costs may be associated with the treatment of wastewater or developing and implementing storm water pollution prevention plans, as well as for monitoring and sampling the storm water runoff from certain of our facilities. Some states also maintain groundwater protection programs that require permits for discharges or operations that may impact groundwater conditions.
The Oil Pollution Act is the primary federal law for oil spill liability. The OPA contains numerous requirements relating to the prevention of and response to petroleum releases into waters of the United States, including the requirement that operators of offshore facilities and certain onshore facilities near or crossing waterways must develop and maintain facility response contingency plans and maintain certain significant levels of financial assurance to cover potential environmental cleanup and restoration costs. The OPA subjects owners of facilities to strict, joint and several liability for all containment and cleanup costs and certain other damages arising from a release, including, but not limited to, the costs of responding to a release of oil to surface waters.
Noncompliance with the Clean Water Act or the OPA may result in substantial administrative, civil and criminal penalties, as well as injunctive obligations. We believe we are in material compliance with the requirements of each of these laws.
Air Emissions. The federal Clean Air Act, as amended (the “CAA”), and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air ActCAA and associated state laws and regulations. We believe that we are in substantial compliance with all applicable air emissions regulations and that we hold all necessary and valid construction and operating permits for our operations.
OnIn June 3, 2016, the EPA expanded its regulatory coverage in thefinalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas industry with additional regulated equipment categories,production and the addition of new rules limiting methane emissions from new or modified sitesnatural gas processing and equipment. Althoughtransmission facilities. In September 2020, the EPA attemptedfinalized two sets of amendments to suspend enforcement of the methane rule, this action was ruled improper2016 Subpart OOOOa standards. The first, known as the 2020 Technical Rule, reduced the 2016 rule’s fugitive emissions monitoring requirements and expanded exceptions to pneumatic pump requirements, among other changes. The second, known as the 2020 Policy Rule, rescinded the methane-specific requirements for certain oil and natural gas sources in the production and processing segments. On January 20, 2021, President Biden issued an Executive Order directing the EPA to rescind the 2020 Technical Rule by September 2021 and consider revising the U.S. Court of Appeals for2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (the “CRA”) resolution passed by Congress that revoked the D.C. Circuit2020 Policy Rule. The CRA did not address the 2020 Technical Rule.
Further, on July 2, 2017. Subsequently, in September 2018,November 15, 2021, the EPA issued a proposed rulemaking that could substantially change the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. Separately, in August 2019, the EPA issued proposed amendments that would that would rescind requirements relatedrule intended to the regulation ofreduce methane emissions from the oil and natural gas industry. Neither rulemaking hassources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain source types that have never been finalized and, therefore, future obligations continue to remain uncertainregulated under the Clean Air Act.CAA (including intermittent vent pneumatic controllers, associated gas, and liquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by the EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022.
As a result of these regulatory changes, the scope of any final methane regulations or the costs for complying with federal methane regulations are uncertain. However, any new regulations could result in stricter permitting requirements, which in turn could delay or impair our ability to obtain air emission permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant.
Climate Change. Numerous reports from scientific and governmental bodies such as the United NationsSixth Assessment Report of the Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas.
In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change (“UNFCCC”) resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formallyOn June 1, 2017, President Trump announced its intent tothat the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2019,2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which withdrawal will becomebecame effective on November 4, 2020. Certain U.S. city and state governmentsFebruary 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the 26th Conference of the Parties of the UNFCCC (“COP26”), over 100 countries have announced their intention to satisfy their proportionate obligations underjoined the pledge. COP26 concluded with the finalization of the Glasgow Climate Pact (the “Glasgow Pact”), which stated long-term global goals (including those in the Paris Agreement. In addition, legislationAgreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. International commitments, re-entry into the Paris Agreement and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations.
Congress has from time to time considered legislation to reduce emissions of GHGs, but no new federal laws have been introducedadopted in Congress that would establish measures restricting GHG emissions inrecent years. However, the United States House of Representatives passed H.R. 5376, known as the Build Back Better Act, on November 3, 2021. The House version of the bill targets methane from oil and a number of states have begun taking actionsgas sources by proposing to control and/or reduce emissions of GHGs.implement fees for excess methane leaking from wells, storage sites, and pipelines as well as fees for new producing and non-producing oil and gases leases and off-shore pipelines.
Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The likelihood of such legislation has increased under the current administration. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce.
In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.
The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations.
Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any
such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects.
Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed.
The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In December 2016, theThe EPA released its final report onevaluated the potential impacts of hydraulic fracturing on drinking water resources concludingand concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibitingprohibits the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.
On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and newly constructed or refractured oil wells. The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. Notably, on October 15, 2018, the EPA published a proposed rule that would make a series of revisions to the 2016 NSPS; these revisions have yet to be finalized. Separately, on August 28, 2019, the EPA published a proposed rule that would that would rescind requirements related to the regulation of methane emissions from the oil and gas industry; these revisions have yet to be finalized.
On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. Additionally, on November 18, 2016, the BLM finalized limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but on September 28, 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations; a lawsuit challenging the September 2018 rule revision is pending.
Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad
Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water. Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015For example, the RRC recently announced an indefinite suspension of certain deep oil and gas wastewater disposal activities in portions of west Texas due to seismicity concerns. The U.S. Geological Survey reporthas identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business.
Surface Damage Statutes (“SDAs”). In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and
negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.
National Environmental Policy Act. Oil and natural gas exploration and production activities onrequiring federal landspermits may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies including the Department of Interior, to evaluate major agencyfederal actions having the potential to significantly impact the human environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assessesevaluate the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that maymust be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. On January 10,July 16, 2020, the Council on Environmental Quality issued a proposed rulerevised NEPA’s implementing regulations in an effort designed to streamline approvals for projects under NEPA.project approvals. Among other revisions, the proposed rule would redefinerules redefines environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The proposed rule would also eliminateeliminated the current “direct,” “indirect,” or “cumulative” categories of effects. This rulemaking process is ongoing.The new regulations are subject to ongoing litigation in several federal district courts, which has been stayed pending an ongoing review of the 2020 rule. On October 6, 2021, the Council on Environmental Quality announced its Phase 1 rule, the first of two planned rules to roll back the 2020 rule. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, onrequire federal lands require governmental permits that are subject to the requirements of NEPA, this process has the potential to delay or impose additional conditions upon the development of oil and natural gas projects.
Endangered Species Act and Migratory Bird Treaty Act. The Endangered Species Act (“ESA”) was established to protect endangered and threatened species. Pursuant to that act, if a species is listed as threatened or endangered, restrictions may be imposed on activities adversely affecting that species’ or its habitat. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act. The U.S. Fish and Wildlife Service (the “FWS”) must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. In August 2019, the FWS and National Marine Fisheries Service (“NMFS”) issued three rules amending implementation of the ESA regulations revising, among other things, the process for listing species and designating critical habitat. A final rule amending howcoalition of states and environmental groups have challenged the three rules and the litigation remains pending. In addition, on December 18, 2020, the FWS amended its regulations governing critical habitat designations; the amended regulations are subject to ongoing litigation. In June 2021, the FWS and suitable habitat areas are designated under the ESA was finalized by the U.S. Fish and Wildlife Service in 2016.NMFS announced plans to begin rulemaking processes to rescind these rules. A critical habitat or suitable habitat designation could result in further material restrictions to land use and may materially delay or prohibit land access for oil and natural gas development. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act (the “MBTA”), which makes it illegal to, among other things, hunt, capture, kill, possess, sell, or purchase migratory birds, nests, or eggs without a permit. This prohibition covers most bird species in the U.S. On January 7, 2021, the Department of the Interior finalized a rule limiting application of the MBTA; however, the Department of the Interior revoked the rule in October 2021 and issued an advance notice of proposed rulemaking seeking comment on the Department’s plan to develop regulations that authorize incidental take under certain prescribed conditions. Future implementation of the rules implementing the Endangered Species Act and the MBTA are uncertain. If the Company was to have a portion of its leases designated as critical or suitable habitat or a protected species were located on a lease, it may adversely impact the value of the affected leases.
Other Regulation of the Oil and Natural Gas Industry. The oil and natural gas industry is extensively regulated by numerous federal, state and local agencies and authorities. Legislation affecting the oil and natural gas industry is under constant review for amendment or expansion, frequently increasing the regulatory burden. Also, numerous departments and agencies, both federal and state, are authorized by statute to issue rules and regulations that are binding on the oil and natural gas industry and its individual members, some of which carry substantial penalties for failure to comply. Although the regulatory burden on the oil and natural gas industry increases our cost of doing business and, consequently, affects our profitability, these burdens generally do not affect us any differently or to any greater or lesser extent than they affect other similar companies in the industry with similar types, quantities and locations of production.
The availability, terms, conditions and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation by the FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to interstateintrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.
Although oil, and natural gas, condensate, and NGL sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and natural gas liquids are not currently regulated and are made at market prices.
Exports of USU.S. Oil Production and Natural Gas Production. In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US.U.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas.
Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:
the location of wells;
the method of drilling and casing wells;
the timing of construction or drilling activities, including seasonal wildlife closures;
the rates of production or “allowables”;
the surface use and restoration of properties upon which wells are drilled;
the plugging and abandoning of wells; and
notice to, and consultation with, surface owners and other third parties.
State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas without a permit and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill.
Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations.
Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,”sales” of natural gas, which include all of our sales of our own production.
Under the Energy Policy Act of 2005 (“EPAct”EPAct 2005”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. FERC also has authority to order the disgorgement of any ill-gotten gains. EPAct also amended the NGA to authorize FERC to “facilitatefacilitate transparency in markets for the sale or transportation of physical natural gas in interstate commerce,” pursuant to which authorization FERC now requires natural gas wholesale market participants, including a number of entities that may not otherwise be subject to FERC’s traditional NGA jurisdiction, to report information
annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.
FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, weregulated. We cannot guarantee that the less stringent regulatory approach currently pursued by FERC and Congress will continue indefinitely into the future nor can we determine what effect, if any, future regulatory changes might have on our natural gas related activities.
Under FERC’s current regulatory regime, interstate transportation services must be provided on an open-access, non-undulynot unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the
means by which a shipper releases its pipeline capacity to another potential shipper, which provisions requireinclude compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules, orincluding the shipper-must-have-title rule, could subject a shipper to substantial penalties from FERC.and disgorgement of any ill-gotten gains.
With respect to its regulation of natural gas pipelines under the NGA, FERC traditionally has not generally required the applicant for construction and operation of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date,In March 2021, FERC has declined to analyze potential upstreamassessed the significance of a project’s GHG emissions and those emissions’ contribution to climate change. FERC compared the project’s reasonably foreseeable GHG emissions to the total GHG emissions of the United States to assess the project’s share of contribution to national GHG levels. FERC announced that could result fromit will also consider state GHG emission reduction targets, to the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects.extent a state has such targets. Finally, FERC noted that it will consider “all appropriate evidence” in future proceedings. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts.
Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmissiontransportation function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.
The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended, (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.2011, the Securing America’s Future Energy: Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2016, and the Protecting our Infrastructure of Pipelines and Enhancing Safety Act of 2019. The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain. In December 2020, Congress passed the Protecting Our Infrastructure of Pipelines and Enhancing Safety Act of 2020 (“PIPES Act of 2020”). In addition to reauthorizing PHMSA, the PIPES Act of 2020 directs the Secretary of Transportation to update or promulgate regulations addressing the safety of certain gas pipeline, gathering, distribution and LNG facilities. On November 15, 2021, PHMSA issued a final rule that expands PHMSA’s safety regulations to more than 400,000 miles of onshore gas gathering pipelines that were previously exempt from PHMSA’s rules. Petitions for reconsideration of this final rule have been filed. Other regulations stemming from the PIPES Act of 2020 are still proceeding through the rulemaking process.
Oil, Condensate and NGLs Sales and Transportation. Sales of oil, condensate and natural gas liquids are not currently regulated and are made at negotiated prices. Nevertheless, Congress could reenact price controls in the future.
The Company’s sales of oil and natural gas liquids are also affected by the availability, terms, conditions and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate
oil and natural gas liquids pipelines to fulfill the requirements of Title XVIII of the Energy Policy Act of 1992 comprised of an indexing system to establish ceilings on interstate oil and natural gas liquids pipeline rates. 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. If the regulations relating to the price, terms and conditions for access to pipeline transportation change, we could face higher transportation costs for our production and, possibly, reduced access to transportation capacity. To the extent it may be necessary for new interstate natural gas pipelines to be built, there may be a more stringent regulatory approach at FERC, which could impact our ability to obtain new interstate pipeline transportation capacity. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.
Further, interstate common carrier oil pipelines must provide service on a non-dulynot unduly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.
In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought ofAt this FERC order by various parties. Due to the pending rehearing of the order and its recency,time, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.
Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. In July 2020, PHMSA promulgated a final rule allowing bulk transportation of LNG by rail. The rule also incorporates additional safety requirements. In November 2021, PHMSA issued a notice of proposed rulemaking, seeking to suspend this final rule.
State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.
The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us.
Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act. The U.S. Commodities and Futures Exchange Commission (“CFTC”(the “CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.
Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affectingaffect derivatives contracts that the Company uses to hedge its exposure to price volatility.
While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending, including a proposal to set position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents. The CFTC also has proposed, but not yet finalized, a rule regarding the capital posting requirements for swap dealers and major swap market participants.pending. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to eitherany applicable rulemaking proceeding. Any final rule in either proceeding could impact the Company’s ability to enter into financial derivative transactions to hedge or mitigate exposure to commodity price volatility and other commercial risks affecting our business.
Worker Health and Safety. We are subject to a number of federal and state laws and regulations, including OSHA, and comparable state statutes, the purpose of which are to protect the health and safety of workers. In 2016, there were substantial revisions to the regulations under OSHA that may have impact to our operations. These changes include among other items; record keeping and reporting, revised crystalline silica standard (which requires the oil and gas industry to implement engineering controls and work practices to limit exposures
below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens.
Commitments and Contingencies
The Company’sOur activities are subject to federal, state and local laws and regulations governing environmental quality and pollution control. Although no assurances can be made, the Company believeswe believe that, absent the occurrence of an extraordinary event, compliance with existing federal, state and local laws, rules and regulations governing the release of materials into the environment or otherwise relating to the protection of the environment will not have a material effect upon theour capital expenditures, earnings or theour competitive position of the Company with respect to itsour existing assets and operations. The CompanyWe cannot predict what effect additional regulation or legislation, enforcement policies included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’sour operations could have on its activities. See “Note 17 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information.
Available Information
We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.
We also make available within the “About Callon”Callon — Governance” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserves, and Nominating and Corporate GovernanceESG, and Operations and Reserves Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042.
ITEM 1A. Risk Factors
Risks Related to the Oil & Natural Gas Industry
Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial conditioncondition.. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the five years ended December 31, 2019,2021, NYMEX WTI prices ranged from a high of $77.41$85.64 per barrel on June 27, 2018October 26, 2021 to a low of $26.19-$36.98 per barrel on February 11, 2016,April 20, 2020, and NYMEX Henry Hub prices ranged from a high of $6.24$23.86 per MMBtu on January 2, 2018February 17, 2021 to a low of $1.49$1.33 per MMBtu on March 4, 2016.September 21, 2020. Prices were particularly volatile in 2020 and 2021, with five-year highs occurring in 2021 and five-year lows occurring in 2020, as a result of multiple significant factors impacting supply and demand in the global oil and natural gas markets, including those relating to the COVID-19 global pandemic. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelablenon-cancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.
In general, prices of oil, natural gas, and NGLs affect the following aspects of our business:
our revenues, cash flows, earnings and returns;
our ability to attract capital to finance our operations and the cost of the capital;
the amount we are allowed to borrow under our Credit Facility;
the profit or loss we incur in exploring for and developing our reserves; and
the value of our oil and natural gas properties.
A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. Additionally, a sustained period of weakness in oil, natural gas and NGLs prices, and the resultant effects of such prices on our drilling economics and ability to raise capital, would require us to reevaluate and postpone or eliminate additional drilling.
Additionally, as of December 31, 2021, approximately 26% of our total net acreage was not held by production, and we had undeveloped leases representing 20% and 1% of our total net acreage scheduled to expire during 2022 and 2023, respectively, in each case assuming no exercise of lease extension options where applicable. The net acreage scheduled to expire in 2022 is substantially comprised of non-core acreage principally located in Texas. If we are required to further curtail our drilling program, we may be unable to continue to hold such leases that are scheduled to expire, which may further reduce our reserves. As a result, if oil, natural gas and/or NGL prices experience a substantial or extended decline in commodity prices may materially and adversely affectsustained period of weakness, our future business, financial condition, results of operations, liquidity, orand ability to finance planned capital expenditures.expenditures may be materially and adversely affected.
If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Price,Prices, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-downan impairment of evaluated oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information.
CompetitiveA negative shift in investor sentiment of the oil and gas industry conditions may negativelycould adversely affect our ability to conduct operations.raise debt and equity capital. We compete with numerousCertain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other companiesindustry sectors have led to lower oil and gas representation in virtually all facetscertain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental, social and governance (“ESG”) activism
and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We face various risks associated with increased activism against oil and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leasesnatural gas exploration and evaluate, bid fordevelopment activities. Opposition toward oil and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnelnatural gas drilling and services that are necessary for the exploration, development activity has been growing globally and operation of our properties. Our ability to increase reservesis particularly pronounced in the future will be dependent onUnited States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non- governmental organizations regarding safety, human rights, climate change, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development. Activism could materially and adversely impact our ability to selectoperate our business and acquire suitable prospects for future exploration and development.raise capital.
The unavailability or high cost of drilling rigs, pressure pumping equipment and crews, other equipment, supplies, water, personnel and oil field services could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget, which could materially and adversely affect our operations and profitability.From time to time, during periods of increasing oil and natural gas prices and in periods in which the levels of exploration and production increase, our industry experiences a shortage of drilling and workover rigs, other equipment, pipes, materials and supplies, water orand qualified personnel. During these periods,As a result of such shortage, the costs and delivery times of rigs, equipment and supplies areoften increase substantially, greater. In addition, during periods in whichas well as the levels of exploration and production increase, the demand for, and wages and costs of drilling rig crews and other experienced personnel and oilfield services, and equipment typically also increase, while the quality of these services and equipment may suffer. This impact may be magnified to the extent that the Company's ability to participate in the commodity price increases is limited by its derivative risk management activities. Cost increases in and shortages of such resources may also result from a variety of other factors beyond our control, such as general inflationary pressures, transportation constraints, and increases in the cost of necessary inputs such as electricity, steel and other raw materials, including as a result of increased tariffs or geopolitical issues.
An excess supply of oil and natural gas may in the future cause us to reduce production and shut-in our wells, any of which could adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures. An excess supply of oil and natural gas may result in transportation and storage capacity constraints. If, in the future, our transportation or storage arrangements become constrained or unavailable, we may incur significant operational costs if there is an increase in price for services or 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. Further, any prolonged shut-in of our wells may result in materially decreased well productivity once we are able to resume operations, and any cessation of drilling and development of our acreage could result in the expiration, in whole or in part, of our leases. All of these impacts may adversely affect our business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures.
Risks Related to the COVID-19 Pandemic
The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, materially adversely affected, and any future outbreak of any other highly infectious or contagious diseases may materially adversely affect, our business, financial position, results of operations, and cash flows. The COVID-19 pandemic, and various governmental actions taken to mitigate its impact, have negatively impacted the global economy, disrupted global supply chains, and created significant volatility and disruption of financial and commodity markets, as well as resulted in an unprecedented decline in demand for oil and natural gas during 2020, which materially adversely affected our business, financial position, results of operations, and cash flows and exacerbated the potential negative impact from many of the other risks described herein, including those relating to our financial position and debt obligations. The pandemic has also increased volatility and, from time to time, caused negative pressure in the capital markets; as a result, in the future, we may experience difficulty accessing the capital or financing needed to fund our operations, which have substantial capital requirements, on satisfactory terms or at all, compounding liquidity risks associated with a material reduction in our revenues and cash flows as a result of any future declines in demand due to the COVID-19 pandemic or any future pandemic.
We expect the COVID-19 pandemic and related economic repercussions to continue to affect our business, financial condition, results of operations, and cash flows. However, the extent of the impact of the COVID-19 pandemic on our business and our operational and financial performance, including our ability to execute our business strategies and initiatives in the expected time frame, is uncertain and depends on various factors that we cannot predict, including the following: the severity and duration of the pandemic; governmental, business and other actions in response to the pandemic; the impact of the pandemic on economic activity; the response of the overall economy and the financial markets; the demand for oil and natural gas, which may be reduced on a prolonged or permanent basis due to a structural shift in the global economy in the way people work, travel, and interact, or in connection with a global recession or depression; any impairment in the value of our tangible or intangible assets which could be recorded as a result of a weaker economic conditions or commodity prices; and the potential effects on our internal controls, including those over financial reporting, as a result of changes in working environments, such as shelter-in-place and similar orders that are applicable to our
employees and business partners, among others. The challenges to working caused by the COVID-19 pandemic and related restrictions may have an impact on our employees’ wellness, which could impact employee retention, productivity and our culture. In addition, we may experience employee turnover as seen with companies throughout the U.S. economy. There are no comparable recent events that provide guidance as to the effect the COVID-19 pandemic may have, and as a result, the ultimate impact of the pandemic is highly uncertain and subject to change.
Operational Risks
Our operations are subject to operating hazards inherent to our industry that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage.
The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write- downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
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. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Risks Related to Marketing and Transportation
Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations,
including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, available manpower, pipeline safety issues, or other reasons. In certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. In addition, we or parties that we utilize might not be able to connect new wells that we complete to pipelines. Our failure to obtain access to processing and transportation facilities and services in a timely manner and on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Other factors that affect our ability to market our production include:
•the extent of domestic production and imports/exports of oil and natural gas;
•federal regulations authorizing exports of LNG, the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
•the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford and Permian oil production to the Gulf Coast;
•the proximity of hydrocarbon production to pipelines;
•the demand for oil and natural gas by utilities and other end users;
•the availability of alternative fuel sources;
•the effects of inclement weather; and
•state and federal regulation of oil, natural gas and NGL marketing and transportation.
We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.
Risks Related to Our Reserves and Drilling Locations
Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This 2021 Annual Report on Form 10-K contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2021 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.
You should not assume that any PV-10 of our estimated proved reserves contained in this 2021 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2021 on the 12-Month Average Realized Prices and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry.
Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures and successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 43% of our total estimated proved reserves as of December 31, 2021 were PUDs. The reserve data included in the Permian Basinreserve reports of West Texasour independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; the availability of capital; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
Risks Related to Technology
We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the Eagle Ford ShaleU.S. government has issued warnings indicating that energy assets may be specific targets of South Texas, cybersecurity threats. Our systems and
insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.
Risks Related to Our Indebtedness and Financial Position
Our business requires significant capital expenditures. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. We intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of debt and equity securities, and asset divestitures. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the ability to borrow under our Credit Facility or our cash flows from operations decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could 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 and business prospects. As of December 31, 2021, we had aggregate outstanding indebtedness of approximately $2.7 billion. Our amount of indebtedness could affect our operations in many ways, including:
•requiring 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 as well as any potential returns to shareholders;
•limiting 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;
•increasing our vulnerability to downturns and adverse developments in our business and the economy;
•limiting our ability to access the capital markets to raise capital on favorable terms, to borrow under our Credit Facility or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
•making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
•making us vulnerable to risks associatedincreases in interest rates as our indebtedness under our Credit Facility may vary with operatingprevailing interest rates;
•placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and
•making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations.
Restrictive covenants in only two geographic regions. the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our second lien senior secured notes and senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness including secured indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; repurchase securities; sell assets; or engage in certain other transactions without the prior consent of the holders or lenders. As a result of this concentration, as compared to
companies that have a more diversified portfolio of properties,these covenants, we are limited in the manner in which we conduct our business and we may be disproportionately exposedunable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we 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 our 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.
Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount and timing of availability of capital we can access, as well as the terms of
any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth.
Our borrowings under our Credit Facility expose us to interest rate risk. Our borrowings under our Credit Facility make us vulnerable to increases in interest rates as they bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 1.00% to 3.00%, depending on the interest rate used and the amount of the loan outstanding in relation to the impactborrowing base. LIBOR is the subject of regional supplynational, international and demand factors, delays or interruptions of production from wells inother regulatory guidance and proposals for reform and is currently being phased-out. At this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruptiontime, it is not possible to predict how markets will respond to alternative reference rates, and the overall financial markets may be disrupted as a result of the processingphase-out or transportationreplacement of oil, natural gasLIBOR. The consequences of these developments with respect to the phase-out of LIBOR cannot be predicted, but could include an increase in the cost of our borrowings under our Credit Facility.
The ability to borrow under our Credit Facility may be restricted to an amount below the amount of borrowings outstanding thereunder or NGLs. Such delays, interruptionsto a lesser amount than what we expect due to future borrowing base reductions or limitationsrestrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $1.6 billion, and as of December 31, 2021, we had an aggregate principal balance of $785.0 million outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in 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 may cause us to not be able to access adequate funding under the Credit Facility. The lenders have sole discretion in determining the amount of the borrowing base and may cause our borrowing base to be redetermined to a materially lower amount, including to below our outstanding borrowings as of such redetermination. In addition, our other debt agreements contain restrictions on the incurrence of additional debt and liens which could limit our ability to borrow under our Credit Facility. If our borrowing base were to be reduced, or if covenants in our indentures restrict our ability to access funding under the Credit Facility, we may be unable to implement our 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 our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
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. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the effectterms of fluctuationsexisting or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.
Any failure to make payments of interest and principal on supplyoutstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.
We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and demanddevelop additional reserves that may be more pronounced within specific geographicrequire the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas producing areas, which may cause these conditionsprices and financial, business and other factors will also affect our ability to occur with greater frequencymaintain or magnify the effectsimprove our leverage position. Many of these conditions.factors are beyond our control.
Risks Related to Acquisitions
We maybe unable to integrate successfully the operations of recent acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions.We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions, including the CarrizoPrimexx Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate recent and future acquisitions successfully could adversely affect our financial condition and results of operations.
Our acquisitions including the recently completed Carrizo Acquisition, may involve numerous risks, including those relatingrelated to:
•operating a larger, more complex combined organization and adding operations;
•assimilating the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;
•acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated;
•the loss of significant key employees, including from the acquired business;
•the inability to obtain satisfactory title to the assets we acquire;
•a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;
•a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;
•the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls;
•the failure to realize expected profitability or growth;
•the failure to realize expected synergies and cost savings;
•coordinating geographically disparate organizations, systems, data, and facilities;
•coordinating or consolidating corporate and administrative functions;
•inconsistencies in standards controls, procedures and policies; and
•integrating relationships with customers, vendors and business partners.
Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. With respect to the Carrizo Acquisition in particular, we have incurred a number of costs associated with completing the Carrizo acquisition and expect to continue to incur significant costs to integrate the business of Carrizo. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all.
If we consummate any future acquisition,acquisitions, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations.
We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.
Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme
weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.
Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, pipeline safety issues, or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.
Other factors that affect our ability to market our production include:
the extent of domestic production and imports/exports of oil and natural gas;
federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;
the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford Shale and Permian Basin oil production to the Gulf Coast;
the proximity of hydrocarbon production to pipelines;
the demand for oil and natural gas by utilities and other end users;
the availability of alternative fuel sources;
the effects of inclement weather; and
state and federal regulation of oil, natural gas and NGL marketing and transportation.
We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.
Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.
Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2019 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.
You should not assume that any PV-10 of our estimated proved reserves contained in this 2019 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2019 on the 12-Month Average Realized Price and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant
capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry.
Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.
Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.
Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.
The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures, successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 57% of our total estimated proved reserves as of December 31, 2019, were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.
The results of our planned development programs in new or emerging shaledevelopment areasand formations may be subject to more uncertainties thanprograms in more establishedareas and formations,and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the Permian Basin are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission (the “RRC”), which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to
gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
Our operations are subject to operating hazards that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage.
The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage.
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. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations.
The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.
We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.
Our business could be negatively affected by security threats. A cyberattack or similar incident could occurand result in information theft, data corruption, operational disruption, damage to our reputation or financial loss. The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.
We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development.
Risks Related to Financial Position
Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.
If the borrowing base under our Credit Facility or our revenues decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could 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 and business prospects. As of December 31, 2019, we had aggregate outstanding indebtedness of approximately $3.2 billion. As a result of the Carrizo Acquisition, our level of indebtedness has significantly increased. Our amount of indebtedness could affect our operations in many ways, including:
requiring 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;
limiting 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;
increasing our vulnerability to downturns and adverse developments in our business and the economy;
limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;
making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;
making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;
placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and
making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations.
Restrictive covenants in the agreements governing our indebtednessmay limit our ability to respond to changes in market conditions or pursue business opportunities.Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; sell assets; or engage in certain other transactions without the prior consent of the lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.
In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we 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 our 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.
Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 0.25% to 2.25% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base.
The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding thereunder. The borrowing base under our Credit Facility is currently $2.5 billion, with an elected commitment amount of $2.0 billion, and as of December 31, 2019, we had an aggregate principal balance of $1.3 billion outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in 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 may cause us to not be able to access adequate funding under the Credit Facility. If our borrowing base were to be reduced, we may be unable to implement our 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 our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment. If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.
We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful.Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.
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. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.
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 our ability to incur additional indebtedness.
We cannot be certain that we will be able to maintain or improve our leverage position.An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.Hedging Program
Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil, and natural gas, and NGL prices and to achieve more predictable cash flow. Our hedges at December 31, 20192021 are in the form of collars, swaps, put and call options, basis swaps, and other structures placed with the commodity trading branches of certain national banking institutions and with certain other commodity trading groups. These hedging arrangements may limit the benefit we could receive from increases in the market or spot prices for oil, natural gas, and natural gas.NGLs. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil, and natural gas, and NGL prices. To the extent that oil, and natural gas, and NGL prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted.
In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production.
Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. Our production is not fully hedged, and we are exposed to fluctuations in oil, natural gas and NGL prices and will be affected by continuing and prolonged declines in oil, natural gas and NGL prices. The total volumes which we hedge through use of our derivative instruments varies from period to period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally hedge for the next 12 to 24 months, subject to the covenants under our Credit Facility. We intend to continue to hedge 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 and may be subject to significant reduction in prices which would have a material negative impact on our results of operations.
Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 26% of our total revenues for the year ended December 31, 2019. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited. A portion of our NOL carryforward balance was generated prior to the effective date of new limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100 percent of taxable income in future years but will start to expire in the tax year 2035. The remainder was generated following such effective date and thus are allowable as a deduction against 80 percent of taxable income in future years and do not expire. Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code of 1986, as amended) at any time during a rolling three-year period. The Company has reduced the total recorded NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilizable before they expire. Future ownership changes or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.
We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:
changes in the valuation of our deferred tax assets and liabilities;
expected timing and amount of the release of any tax valuation allowances;
tax effects of stock-based compensation;
costs related to intercompany restructurings;
changes in tax laws, regulations or interpretations thereof; or
lower than anticipated future earnings in our taxing jurisdictions.
In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
Legal and Regulatory Risks
We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties.Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties—Regulations.” These laws and regulations may:
•require that we acquire permits before commencing drilling;
•regulate the spacing of wells and unitization and pooling of properties;
•impose limitations on production or operational, emissions control and other conditions on our activities;
•restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations;
•limit or prohibit drilling activities on protected areas, such as wetlands and wilderness;
•impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or
•require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantlingdecommissioning abandoned wells and production facilities.
Significant expenditures may be required to comply with governmental laws and regulations applicable to us. In addition, failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, permit revocations, requirements for additional pollution controls or injunctions limiting or prohibiting operations.
The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Additionally, Congress and federal, state and local agencies frequently revise environmental laws and regulations, and such changes could result in increased costs for environmental compliance, such as emissions monitoring and control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease from time to time, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term.
Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other
equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents.
Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA published permitting guidance addressing the use of diesel fuel in hydraulic fracturing operations, and issued an interpretive memorandum clarifying thatregulates hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection ControlUIC program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emissionrecently taken steps to strengthen its methane standards, including most recently in November 2021, when the EPA issued a proposed rule intended to reduce methane emissions from oil and gas sources. The proposed rule would make the existing regulations in Subpart OOOOa more stringent and create a Subpart OOOOb to expand reduction requirements for new, modified, and reconstructed oil and gas sources, including standards focusing on certain equipment, processessource types that have never been regulated under the CAA (including intermittent vent pneumatic controllers, associated gas, and activities acrossliquids unloading facilities). In addition, the proposed rule would establish “Emissions Guidelines,” creating a Subpart OOOOc that would require states to develop plans to reduce methane emissions from existing sources that must be at least as effective as presumptive standards set by EPA. Under the proposed rule, states would have three years to develop their compliance plan for existing sources and the regulations for new sources would take effect immediately upon issuance of a final rule. The EPA is expected to issue both a supplemental proposed rule, which may expand or modify the current proposed rule, and final rule by the end of 2022. The scope of future obligations remains uncertain; however, given the long-term trend towards increasing regulation, future federal regulation of methane and other greenhouse gas emissions from the oil and natural gas sector, although the EPA proposed amendments in August 2019 that would rescind requirements related to the regulation of methane emissions. Additionally, the BLM publishedindustry remains a final rule in March 2015 containing disclosure requirements and other mandates for hydraulic fracturing on federal and Indian lands. Although the BLM subsequently rescinded the rule in December 2017, the rescission has been challenged in federal court by several environmental groups and states. In November 2016, the BLM also issued rules to limit methane emissions from new and existing oil and gas operations on federal lands, but subsequently relaxed and rescinded certain requirements of the rules in September 2018; a lawsuit challenging the September 2018 rule revision is pending.possibility.
In some areas of Texas, including the Eagle Ford Shale and Permian, Basin, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or limitimpose new limits on the volumes of, new injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs.
Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC issued theThe RRC’s “well integrity rule” in May 2013, which includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in October 2014, the RRC adopted a rule requiringrules require applicants for certain new water disposal wells to conduct seismic activity searches using the U.S. Geological Survey to determine the potential for earthquakes within a circular area of 100 square miles. The rule also clarifiesFurther, the RRC’sRRC has authority to modify, suspend or terminate a disposal well permit if scientific data indicates a disposal well is likely to contribute to seismic activity. The RRC has used this authority to deny permits for, wasteand limit volumes for, disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular.
In December 2016,The EPA issued the EPA released its final report “Hydraulic Fracturing for Oil and Gas: Impacts from the Hydraulic Fracturing Water Cycle on Drinking Water Resources in the United States.” ThisStates” report, concludesconcluding that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business.
There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water
disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.
Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules and proposed additional rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce or tax emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of some existing and proposed GHG rules and regulations, see “Regulations.“Business and Properties—Regulations.”
In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195nearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formallyOn June 1, 2017, President Trump announced its intent tothat the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 2019,2020. However, on January 20, 2021, President Biden issued written notification to the United Nations of the United States’ intention to rejoin the Paris Agreement, which withdrawal will becomebecame effective on November 4, 2020. Certain U.S. city and state governmentsFebruary 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a pact that aims to reduce global methane emissions at least 30% below 2020 levels by 2030. Since its formal launch at the COP26, over 100 countries have announced their intention to satisfy their proportionate obligations underjoined the pledge. The COP26 concluded with the finalization of the Glasgow Pact, which stated long-term global goals (including those in the Paris Agreement. AAgreement) to limit the increase in the global average temperature and emphasized reductions in GHG emissions. In addition, a number of states have begun taking actions to control or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon
fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. International commitments, re-entry into the Paris Agreement, and President Biden’s executive orders may result in the development of additional regulations or changes to existing regulations. At the federal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and may be proposed or adopted in the future. The likelihood of such legislation has increased due to the current administration. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.
In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.
Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere and climate change may produce significant physical effects on weather conditions, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods, or increases in our costs of operation, or reductions in the efficiency of our operations, impacts on our personnel, supply chain, or distribution chain, as well as potentially increased costs for insurance coverages in the aftermath of such effects. Our ability to mitigate
the adverse physical impacts of climate change depends in part upon our disaster preparedness and response and business continuity planning.
Current or proposed financial legislation and rulemaking could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.Title VII of the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Dodd-Frank Act”) establishes federal oversight and regulation of over-the-counter derivatives and requires the U.S. Commodity Futures Trading Commission (the “CFTC”)CFTC and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.
Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet finalized position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. On January 24, 2020, U.S. banking regulators published a new approach for calculating the quantum of exposure of derivative contracts under their regulatory capital rules. This approach to measuring exposure is referred to as the standardized approach for counterparty credit risk or SA-CCR. It requires certain financial institutions to comply with significantly increased capital requirements for over-the-counter commodity derivatives beginning on January 1, 2022. In addition, on September 15, 2020, the CFTC issued a final rule regarding the capital a swap dealer or major swap participant is required to set aside with respect to its swap business, which has a compliance date of October 6, 2021. These two sets of regulations and the increased capital requirements they place on certain financial institutions may reduce the number of products and counterparties in the over-the-counter derivatives market available to us and could result in significant additional costs being passed through to end-users like us. On January 14, 2021, the CFTC published a final rule on position limits for certain commodities futures and their economically equivalent swaps, though like several other rules there is a bona fide hedging exemption to the application of such rule. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.
It is not possible at this time to predict the timing or contents of the CFTC’s final rules on position limits or capital requirements. Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions and/or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When aAfter the compliance date for the final rule on capital requirements, is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.
In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially
reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes).
If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.
Tax laws and regulations may change over time, andRisks
Our ability to use our existing net operating loss (“NOL”) carryforwards or other tax attributes could be limited. A significant portion of our NOL carryforward balance was generated prior to the recently passed comprehensive tax reform bill could adversely affect our business and financial condition. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to aseffective date of limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act that significantly reformsof 2017 (the “Tax Act”) and are allowable as a deduction against 100% of taxable income in future years, but will start to expire in the 2035 taxable year. The remainder were generated following such effective date, and thus generally allowable as a deduction against 80% of taxable income in future years (with an exception to this rule due to the enactment of the Coronavirus Aid, Relief, and Economic Security Act (the “CARES Act”), whereby the utilization of NOLs was temporarily expanded for taxable years beginning before 2021). Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 (“Section 382”) of the Internal Revenue Code of 1986, as amended (the “Code”). The Tax Act, among other things, (i) permanently reduces, generally imposes, upon the U.S. corporate income tax rate, (ii) repeals the corporate alternative minimum tax, (iii) eliminates the deduction for certain domestic production activities, (iv) imposes new limitationsoccurrence of an ownership change (discussed below), an annual limitation on the utilizationamount of net operating losses, and (v) provides for more general changesour pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the taxationvalue of corporations, including changes to cost recovery rules andour stock immediately prior to the deductibilityownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of interest expense, which may impactmore than 50 percentage points by one or more “5% shareholders” (as defined in the taxationCode) at any time
during a rolling three-year period. Future ownership changes and/or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.
Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of oilour income or other tax returns could adversely affect our financial condition and gas companies. The Tax Act is complexresults of operations. We are subject to income taxes in the U. S., and far-reachingour domestic tax assets and we cannot predict with certaintyliabilities are subject to the resulting impact its enactment has on us. The ultimate impactallocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including the following: changes in the valuation of our deferred tax assets and liabilities; expected timing and amount of the Tax Act may differ from our estimates duerelease of any tax valuation allowances; tax effects of stock-based compensation; costs related to intercompany restructurings; changes in tax laws, regulations or interpretations and assumptions made by us as well as additional regulatory guidance thatthereof; or lower than anticipated future earnings in our taxing jurisdictions. In addition, we may be issuedsubject to audits of our income, sales and anyother transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.
Tax laws and regulations may change over time and such changes in interpretations or assumptions could adversely affect our business and financial condition. See “Note 12 - Income Taxes” to our consolidated financial statements included elsewhere in this 2019 Annual Report on Form 10-K for additional information.
In addition, from 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, including (i) the elimination of the immediate deduction for intangible drilling and development costs, (ii) the repeal of the percentagechanges to a depletion allowance for oil and natural gas properties, and (iii) the implementation of a carbon tax, (iv) an extension of the amortization period for certain geological and geophysical expenditures.expenditures, (v) changes to tax rates, and (vi) the introduction of a minimum tax. While these specific changes were not included in the Tax Act or the CARES Act, no accurate prediction can be made as to whether any such legislative changes or other changes (such as those contained in the Build Back Better Act) 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. The elimination of such U.S. federal tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-U.S. taxes (including the imposition of, or increases in production, severance or similar taxes) could adversely affect our business and financial condition.
Other Material Risks
Competitive industry conditions may negatively affect our ability to conduct operations.We compete with numerous other companies in virtually all facets of our business. Our competitors in development, exploration, acquisitions and production include major integrated oil and gas companies and smaller independents as well as numerous financial buyers. Some of our competitors may be able to pay more for desirable leases and evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources permit. We also compete for the materials, equipment, personnel and services that are necessary for the exploration, development and operation of our properties. Our ability to increase reserves in the future will be dependent on our ability to select and acquire suitable prospects for future exploration and development.
All of our producing properties are located in the Permian of West Texas and the Eagle Ford of South Texas, making us vulnerable to risks associated with operating in only two geographic regions. As a result of this concentration, as compared to companies that have a more diversified portfolio of properties, we may be disproportionately exposed to the impact of regional supply and demand factors, severe weather, delays or interruptions of production from wells in this area caused by governmental regulation, specific taxes or other regulatory legislation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services, or market limitations or interruption of the processing or transportation of oil, natural gas or NGLs. Such delays, interruptions or limitations could have a material adverse effect on our financial condition and results of operations. In addition, the effect of fluctuations on supply and demand may be more pronounced within specific geographic oil and natural gas producing areas, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions.
The results of our planned development programs in new or emerging shale development areas and formations may be subject to more uncertainties than programs in more established areas and formations, and may not meet our expectations for reserves or production. The results of our horizontal drilling efforts in emerging areas and formations of the actionsPermian are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of activist shareholders.which are subject to well spacing, density and proration requirements of the RRC, which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.
The loss of key personnel, or inability to employ a sufficient number of qualified personnel, could adversely affect our ability to operate. We have been the subject of an activist shareholderdepend, and will continue to depend in the past. Respondingforeseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to shareholder activism can be costlyretain our senior officers, other key employees, and time-consuming, disrupt our operations and divert the attentionthird party consultants, many of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties aswhom are not subject to employment agreements, is important to our future direction, strategysuccess and growth. The unexpected loss of the services of one or leadership andmore of these individuals could have a detrimental effect on our business. Also, we may resultexperience employee turnover or labor shortages if our business requirements, compensation, benefits and/or perquisites are inconsistent with the expectations of current or prospective employees, or if workers pursue employment in fields with less volatility than in the loss of potential business opportunities, harmenergy industry. If we are unsuccessful in our abilityefforts to attract new investors, customers and joint venture partners and causeretain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected tocompetitive position, our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy maybusiness could be adversely affected.
Risks RelatedThe inability of one or more of our customers to meet their obligations to us may adversely affect our Common Stockfinancial results.Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 20% of our total revenues for the year ended December 31, 2021. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.
Our bylaws designate the Court of Chancery of the State of Delaware (the “Court of Chancery”) as the sole and exclusive forum for certain types of actions and proceedings that may be initiated by our shareholders, which could limit our shareholders’ ability to obtain a favorable judicial forum for disputes with us or our directors, officers, or other employees.Our bylaws provide that, unless we consent in writing to the selection of an alternative forum, the sole and exclusive forum for (i) any derivative action or proceeding brought on our behalf, (ii) any action or proceeding asserting a claim for breach of a fiduciary duty owed by any current or former director, officer, or other employee of our company to us or our shareholders, (iii) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company arising pursuant to any provision of the Delaware General Corporate Law (the “DGCL”) or our charter or bylaws (as each may be amended from time to time), (iv) any action or proceeding asserting a claim against us or any current or former director, officer, or other employee of our company governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Court of Chancery shall be the Court of Chancery or, if and only if the Court of Chancery lacks subject matter jurisdiction, any state court located within the State of Delaware or, if and only if such state courts lack subject matter jurisdiction, the federal district court for the District of Delaware, in all cases to the fullest extent permitted by law and subject to the court’s having personal jurisdiction over the indispensable parties named as defendants.
Our exclusive forum provision is not intended to apply to claims arising under the Securities Act or the Exchange Act. To the extent the provision could be construed to apply to such claims, there is uncertainty as to whether a court would enforce the forum selection provision with respect to such claims, and in any event, our shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder.
Any person or entity purchasing or otherwise acquiring any interest in shares of our capital stock is deemed to have received notice of and consented to the foregoing forum selection provision. This provision may limit our shareholders’ ability to bring a claim in a judicial forum that they find favorable for disputes with us or our directors, officers, or other employees, which may discourage such lawsuits.
Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations.
Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock.Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.
We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of
our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock.
General Risk Factors
We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected.
Future sales of our common stock in the public market could reduce our stock price, and any additional capital raised by us through the sale of our common stock or other securities may dilute a shareholder’s ownership in us.In the future, we may continue to issue securities to raise capital. We may also continue to acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities.
ITEM 1B. Unresolved Staff Comments
None.
ITEM 3. Legal Proceedings
We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.
ITEM 4. Mine Safety Disclosures
Not applicable.
PART II.
ITEM 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Market Information
Our common stock trades on the New York Stock Exchange (“NYSE”) under the symbol “CPE”.
Reverse Stock Split
On August 7, 2020, the Board of Directors effected a reverse stock split of the Company’s outstanding shares of common stock at a ratio of 1-for-10 and proportionately reduced the total number of authorized shares from 525,000,000 to 52,500,000 shares. The Company’s common stock began trading on a split-adjusted basis on the NYSE at the market open on August 10, 2020. All share and per share amounts in this Annual Report on Form 10-K for periods prior to August 7, 2020 have been retroactively adjusted to reflect the reverse stock split. The par value of the common stock was not adjusted as a result of the reverse stock split.
Holders
As of February 21, 202018, 2022 the Company had approximately 2,5971,182 common stockholders of record.
Dividends
We have not paid any cash dividends on our common stock to date and presently do not expect to declare or pay any cash dividends on our common stock in the foreseeable future as we intendnear-term focus is to reinvest our cash flows and earnings into our business and continue to pay down debt. The declarationHowever, we continuously monitor many internal and paymentexternal factors as we consider when, or if, we should implement shareholder return programs. These factors include our current and projected financial performance; our debt metrics, covenants and absolute amounts borrowed; commodity price outlooks; cash requirements; corporate and strategic plans; macroeconomic indicators; among other items. Ultimately, the timing, amount and form of future dividends, if any, is subject to the discretion of our Board of Directors and to certain limitations imposed under Delaware corporate law and the agreements governing our debt obligations. The timing, amount and form of dividends, if any, will depend on, among other things, our results of operations, financial condition, cash requirements and other factors deemed relevant by our Board of Directors. In addition, certain of our debt facilities contain restrictions on the payment of dividends to the holders of our common stock.
Performance Graph
The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.
The stock price performance graph below compares the yearly percentage change in the cumulative total stockholder return on the Company’s common stock with the cumulative total return of the Standard & Poor’s 500 Index (“S&P 500 Index”) and a peer group of companies to which we compare our performance from December 31, 20142016 through December 31, 2019.2021. The companies in the peer group include Cimarex Energy Co., Centennial Resource Development, Inc., Laredo Petroleum, Inc., Magnolia Oil & Gas Corporation, Matador Resources, Inc., Oasis Petroleum, Inc., Parsley Energy, Inc., PDC Energy, Inc., QEP Resources, Inc.,Ranger Oil Corporation and SM Energy Company, Whiting Petroleum Corporation, and WPX Energy, Inc.Company. The Company’s historical stock prices used in the graph below have been retroactively adjusted to reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020.
The stock price performance graph and related information shall not be deemed “soliciting material” or to be “filed” with the SEC, nor shall information be incorporated by reference into any future filing under the Securities Act of 1933 or Securitiesthe Exchange Act, of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing
Comparison of Five Year Cumulative Total Return
Assumes Initial Investment of $100
December 31, 20192021
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
Company/Market/Peer Group | | 2016 | | 2017 | | 2018 | | 2019 | | 2020 | | 2021 |
Callon Petroleum Company | | $100 | | | $79 | | | $42 | | | $31 | | | $9 | | | $31 | |
S&P 500 Index - Total Returns | | 100 | | | 122 | | | 116 | | | 153 | | | 181 | | | 233 | |
Peer Group | | 100 | | | 85 | | | 63 | | | 51 | | | 26 | | | 85 | |
Unregistered Sales of Equity Securities and Use of Proceeds
Pursuant to the closing of the Primexx Acquisition, the Company issued 8.84 million shares of the Company’s common stock as a portion of the total consideration for the assets acquired. Also pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration equal to 0.2 million shares of the Company’s common stock.
Pursuant to the closing of the Second Lien Note Exchange, the Company exchanged $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of its common stock, which equated to 5.5 million shares.
All shares issued pursuant to the Primexx Acquisition and the Second Lien Note Exchange were issued in reliance upon the exemption from the registration requirements of the Securities Act provided by Section 4(a)(2) of the Securities Act as sales by an issuer not involving any public offering. The issuance of such shares in connection with the Primexx Acquisition and the Second Lien Note Exchange did not involve a public offering for purposes of Section 4(a)(2) because of, among other things, it was being made only to accredited investors, and in connection therewith, the Company did not engage in general solicitation or advertising with regard to the issuance of such shares.
|
| | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
Company/Market/Peer Group | | 2014 | | 2015 | | 2016 | | 2017 | | 2018 | | 2019 |
Callon Petroleum Company | |
| $100 |
| |
| $153 |
| |
| $282 |
| |
| $223 |
| |
| $119 |
| |
| $89 |
|
S&P 500 Index - Total Returns | | 100 |
| | 101 |
| | 114 |
| | 138 |
| | 132 |
| | 174 |
|
Peer Group | | 100 |
| | 74 |
| | 125 |
| | 98 |
| | 67 |
| | 56 |
|
ITEM 6. Selected Financial DataReserved
The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2019 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results.
|
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | 2017 | | 2016 | | 2015 |
Statement of Operations Data (1) | | (In thousands, except per share amounts) |
Oil, natural gas, and NGL revenue | |
| $671,572 |
| |
| $587,624 |
| |
| $366,474 |
| |
| $200,851 |
| |
| $137,512 |
|
Total operating expenses | | 498,914 |
| | 328,094 |
| | 225,028 |
| | 248,328 |
| | 346,622 |
|
Income (loss) from operations | | 172,658 |
| | 259,530 |
| | 141,446 |
| | (47,477 | ) | | (209,110 | ) |
Income (loss) available to common stockholders (2) | | 67,928 |
| | 300,360 |
| | 120,424 |
| | (99,108 | ) | | (248,034 | ) |
Income (loss) available to common stockholders per common share: | | | | | | | | | | |
Basic | |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
| |
| ($0.78 | ) | |
| ($3.77 | ) |
Diluted | |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
| |
| ($0.78 | ) | |
| ($3.77 | ) |
Weighted average common shares outstanding: | | | | | | | | | | |
Basic | | 233,140 |
| | 216,941 |
| | 201,526 |
| | 126,258 |
| | 65,708 |
|
Diluted | | 233,550 |
| | 217,596 |
| | 202,102 |
| | 126,258 |
| | 65,708 |
|
Statement of Cash Flows Data | | | | | | | | | | |
Net cash provided by operating activities | |
| $476,316 |
| |
| $467,654 |
| |
| $229,891 |
| |
| $120,774 |
| |
| $89,319 |
|
Net cash used in investing activities | | (388,389 | ) | | (1,324,057 | ) | | (1,072,532 | ) | | (866,287 | ) | | (259,160 | ) |
Net cash provided by (used in) financing activities | | (90,637 | ) | | 844,459 |
| | 217,643 |
| | 1,397,282 |
| | 170,097 |
|
Balance Sheet Data | | | | | | | | | | |
Total oil and natural gas properties | |
| $6,669,118 |
| |
| $3,718,858 |
| |
| $2,513,491 |
| |
| $1,475,401 |
| |
| $711,386 |
|
Total assets | | 7,194,838 |
| | 3,979,173 |
| | 2,693,296 |
| | 2,267,587 |
| | 788,594 |
|
Long-term debt (3) | | 3,186,109 |
| | 1,189,473 |
| | 620,196 |
| | 390,219 |
| | 328,565 |
|
Stockholders’ equity | | 3,223,308 |
| | 2,445,208 |
| | 1,855,966 |
| | 1,733,402 |
| | 362,758 |
|
Proved Reserves Data (4) | | | | | | | | | | |
Oil (MBbls) | | 346,361 |
| | 180,097 |
| | 107,072 |
| | 71,145 |
| | 43,348 |
|
Natural gas (MMcf) | | 757,134 |
| | 350,466 |
| | 179,410 |
| | 122,611 |
| | 65,537 |
|
NGLs (MBbls) | | 67,462 |
| | — |
| | — |
| | — |
| | — |
|
Total proved reserves (MBoe) | | 540,012 |
| | 238,508 |
| | 136,974 |
| | 91,580 |
| | 54,271 |
|
Standardized measure of discounted future net cash flows | |
| $4,951,026 |
| |
| $2,941,293 |
| |
| $1,556,682 |
| |
| $809,832 |
| |
| $570,890 |
|
| |
(1) | Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. |
| |
(2) | Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208.4 million as a result of the ceiling test limitation and $108.8 million of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation. |
| |
(3) | See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information. |
| |
(4) | The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis. |
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
AThe following management’s discussion and analysis ofdescribes the Company’s financial condition andprincipal factors affecting our results of operations, for the year ended December 31, 2017 can be found in “Part II, Item 7. Management's Discussionliquidity, capital resources and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2018, which was filed with the SEC on February 27, 2019 and is incorporated herein by reference.
General
The followingcontractual cash obligations. This discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing.
Our website address is www.callon.com. AllA discussion and analysis of our filings with the SEC are available freeCompany’s financial condition and results of charge through our website as soon as reasonably practicable after we file them with, or furnish them to,operations for the SEC. Information on our website does not form partyear ended December 31, 2019 can be found in “Part II, Item 7. Management's Discussion and Analysis of this 2019Financial Condition and Results of Operations” of its Annual Report on Form 10-K.10-K for the year ended December 31, 2020, which was filed with the SEC on February 25, 2021.
General
We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian BasisBasin in West Texas. In 2019, though our acquisition of Carrizo, we doubled our core acreage position in the Delaware Basin and enteredTexas, as well as the Eagle Ford Shale.
in South Texas. Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian, Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and more recently as a result of the Carrizo Acquisition, the Eagle Ford Shale.Ford. We have assembled a multi-year inventory of potential horizontal well locations and intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and through acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.
OverviewFinancial and Operational Highlights
Significant Accomplishments in 2019
On December 20, 2019, we completedFor discussion of our significant financial and operational highlights for the Carrizo Acquisition which increased our portfolio to: (i) over 116,000 net acres in the Permian Basin, which doubled our footprint in the Southern Delaware Basin and (ii) expanded our portfolio to include over 76,000 net acres in the mature, high-margin, free cash flow generating Eagle Ford Shale.
In connection with the Carrizo Acquisition, we entered into the Credit Facility, which has a maximum credit amount of $5.0 billion. As ofyear ended December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion.2021, please see “Part 1. Items 1 and 2. Business and Properties — Overview — Major Developments in 2021”.
During 2019, we completed divestitures of non-core assets for aggregate net proceeds of $294.4 million. In addition, we could receive cash for settlements of our contingent consideration arrangement of up to $60.0 million if crude oil prices exceed specified thresholds for each of the years of 2019 through 2021.
Our total production in 2019 increased by 26% to 15.1 MMBoe (77% oil) as compared to 2018.
On July 18, 2019, we redeemed all of the outstanding Preferred Stock for $73.0 million.
| |
• | For the year ended December 31, 2019, we drilled 63 gross (55.7 net) horizontal wells, completed 55 gross (47.1net) horizontal wells and had, as of December 31, 2019, 64 gross (57.7 net) horizontal wells awaiting completion.
|
Estimated proved reserves as of December 31, 2019 were 540.0 MMBoe (64% oil), with 43% classified as proved developed.
Reserves Growth
As of December 31, 2019, our estimated proved reserves increased 126% to 540.0 MMBoe compared to 238.5 MMBoe of estimated proved reserves at year-end 2018. Our significant growth in proved reserves was primarily attributable to the Carrizo Acquisition, along with our horizontal development efforts. Our estimated proved reserves at year-end 2019 and 2018 were 64% and 76% oil, respectively.
Results of Operations
The following table sets forth certain operating information with respect to the Company’s oil and natural gas operations for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | $ Change | | % Change |
Total production | | | | | | | | |
Oil (MBbls) | | | | | | | | |
Permian | | 14,475 | | 14,113 | | 362 | | | 3 | % |
Eagle Ford | | 7,749 | | 9,430 | | (1,681) | | | (18 | %) |
Total oil | | 22,224 | | 23,543 | | (1,319) | | | (6 | %) |
| | | | | | | | |
Natural gas (MMcf) | | | | | | | | |
Permian | | 29,682 | | 32,087 | | (2,405) | | | (7 | %) |
Eagle Ford | | 7,704 | | 8,714 | | (1,010) | | | (12 | %) |
Total natural gas | | 37,386 | | 40,801 | | (3,415) | | | (8 | %) |
| | | | | | | | |
NGLs (MBbls) | | | | | | | | |
Permian | | 5,155 | | 5,390 | | (235) | | | (4 | %) |
Eagle Ford | | 1,284 | | 1,460 | | (176) | | | (12 | %) |
Total NGLs | | 6,439 | | 6,850 | | (411) | | | (6 | %) |
| | | | | | | | |
Total production (MBoe) | | | | | | | | |
Permian | | 24,577 | | 24,851 | | (274) | | | (1 | %) |
Eagle Ford | | 10,317 | | 12,342 | | (2,025) | | | (16 | %) |
Total barrels of oil equivalent | | 34,894 | | 37,193 | | (2,299) | | | (6 | %) |
| | | | | | | | |
Total daily production (Boe/d) | | 95,599 | | 101,620 | | (6,021) | | | (6 | %) |
Oil as % of total daily production | | 64 | % | | 63 | % | | | | 1 | % |
| | | | | | | | |
Benchmark prices(1) | | | | | | | | |
WTI (per Bbl) | | $67.94 | | $39.38 | | $28.56 | | | 73 | % |
Henry Hub (per Mcf) | | 3.72 | | 2.13 | | 1.59 | | | 75 | % |
| | | | | | | | |
Average realized sales price (excluding impact of derivative settlements) | | | | | | | | |
Oil (per Bbl) | | | | | | | | |
Permian | | $68.20 | | $37.23 | | $30.97 | | | 83 | % |
Eagle Ford | | 68.27 | | 34.49 | | 33.78 | | | 98 | % |
Total oil | | 68.22 | | 36.13 | | 32.09 | | | 89 | % |
| | | | | | | | |
Natural gas (per Mcf) | | | | | | | | |
Permian | | 3.69 | | 1.05 | | 2.64 | | | 251 | % |
Eagle Ford | | 4.13 | | 2.07 | | 2.06 | | | 100 | % |
Total natural gas | | 3.78 | | 1.27 | | 2.51 | | | 198 | % |
| | | | | | | | |
NGL (per Bbl) | | | | | | | | |
Permian | | 30.60 | | 11.91 | | 18.69 | | | 157 | % |
Eagle Ford | | 28.12 | | 11.71 | | 16.41 | | | 140 | % |
Total NGL | | 30.11 | | 11.87 | | 18.24 | | | 154 | % |
| | | | | | | | |
Total average realized sales price (per Boe) | | | | | | | | |
Permian | | 51.05 | | 25.09 | | 25.96 | | | 103 | % |
Eagle Ford | | 57.86 | | 29.20 | | 28.66 | | | 98 | % |
Total average realized sales price | | $53.06 | | $26.45 | | $26.61 | | | 101 | % |
| | | | | | | | |
|
| | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 (1) | | 2018 | | $ Change | | % Change |
Total production (2) | | | | | | | | |
Oil (MBbls) | | 11,665 |
| | 9,443 |
| | 2,222 |
| | 24 | % |
Natural gas (MMcf) | | 19,718 |
| | 15,447 |
| | 4,271 |
| | 28 | % |
NGLs (MBbls) | | 135 |
| | — |
| | 135 |
| | 100 | % |
Total barrels of oil equivalent (MBoe) | | 15,086 |
| | 12,018 |
| | 3,068 |
| | 26 | % |
Total daily production (Boe/d) | | 41,331 |
| | 32,926 |
| | 8,405 |
| | 26 | % |
Oil as % of total daily production | | 77 | % | | 79 | % | | | | |
|
| | | | | | | | |
Average realized sales price (excluding impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | |
| $54.27 |
| |
| $56.22 |
| |
| ($1.95 | ) | | (3 | %) |
Natural gas (per Mcf) | | 1.85 |
| | 3.67 |
| | (1.82 | ) | | (50 | %) |
NGLs (per Bbl) | | 15.37 |
| | — |
| | 15.37 |
| | 100 | % |
Total (per Boe) | | 44.52 |
| | 48.90 |
| | (4.38 | ) | | (9 | %) |
| | | | | | | | |
Average realized sales price (including impact of settled derivatives) | | | | | | | | |
Oil (per Bbl) | |
| $53.31 |
| |
| $53.31 |
| |
| $— |
| | — | % |
Natural gas (per Mcf) | | 2.22 |
| | 3.69 |
| | (1.47 | ) | | (40 | %) |
NGLs (per Bbl) | | 15.37 |
| | — |
| | 15.37 |
| | 100 | % |
Total (per Boe) | | 44.27 |
| | 46.63 |
| | (2.36 | ) | | (5 | %) |
| | | | | | | | |
Revenues (in thousands) | | | | | | | | |
Oil | |
| $633,107 |
| |
| $530,898 |
| |
| $102,209 |
| | 19 | % |
Natural gas | | 36,390 |
| | 56,726 |
| | (20,336 | ) | | (36 | %) |
NGLs | | 2,075 |
| | — |
| | 2,075 |
| | 100 | % |
Total revenues | |
| $671,572 |
| |
| $587,624 |
| |
| $83,948 |
| | 14 | % |
| | | | | | | | |
Additional per Boe data | | | | | | | | |
Lease operating expense (3) | | 6.09 |
| | 5.76 |
| | 0.33 |
| | 6 | % |
Production taxes | | 2.83 |
| | 2.98 |
| | (0.15 | ) | | (5 | %) |
| | | | | | | | |
Benchmark prices(4) | | | | | | | | |
WTI (per Bbl) | |
| $56.98 |
| |
| $65.23 |
| |
| ($8.25 | ) | | (13 | %) |
Henry Hub (per Mcf) | | 2.56 |
| | 3.15 |
| | (0.59 | ) | | (19 | %) |
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | $ Change | | % Change |
Revenues (in thousands) | | | | | | | | |
Oil | | | | | | | | |
Permian | | $987,195 | | $525,412 | | $461,783 | | | 88 | % |
Eagle Ford | | 529,030 | | 325,255 | | 203,775 | | | 63 | % |
Total oil | | 1,516,225 | | 850,667 | | 665,558 | | | 78 | % |
| | | | | | | | |
Natural gas | | | | | | | | |
Permian | | 109,640 | | 33,815 | | 75,825 | | | 224 | % |
Eagle Ford | | 31,853 | | 18,051 | | 13,802 | | | 76 | % |
Total natural gas | | 141,493 | | 51,866 | | 89,627 | | | 173 | % |
| | | | | | | | |
NGLs | | | | | | | | |
Permian | | 157,757 | | 64,201 | | 93,556 | | | 146 | % |
Eagle Ford | | 36,104 | | 17,094 | | 19,010 | | | 111 | % |
Total NGLs | | 193,861 | | 81,295 | | 112,566 | | | 138 | % |
| | | | | | | | |
Total revenues | | | | | | | | |
Permian | | 1,254,592 | | 623,428 | | 631,164 | | | 101 | % |
Eagle Ford | | 596,987 | | 360,400 | | 236,587 | | | 66 | % |
Total revenues | | $1,851,579 | | $983,828 | | $867,751 | | | 88 | % |
| | | | | | | | |
Additional per Boe data | | | | | | | | |
Lease operating expense | | | | | | | | |
Permian | | $5.27 | | $4.71 | | $0.56 | | | 12 | % |
Eagle Ford | | 7.13 | | 6.25 | | 0.88 | | | 14 | % |
Total lease operating expense | | $5.82 | | $5.22 | | $0.60 | | | 11 | % |
| | | | | | | | |
Production and ad valorem taxes | | | | | | | | |
Permian | | $2.75 | | $1.59 | | $1.16 | | | 73 | % |
Eagle Ford | | 3.16 | | 1.87 | | 1.29 | | | 69 | % |
Total production and ad valorem taxes | | $2.87 | | $1.68 | | $1.19 | | | 71 | % |
| | | | | | | | |
Gathering, transportation and processing | | | | | | | | |
Permian | | $2.54 | | $2.29 | | $0.25 | | | 11 | % |
Eagle Ford | | 1.80 | | 1.66 | | 0.14 | | | 8 | % |
Total gathering, transportation and processing | | $2.32 | | $2.08 | | $0.24 | | | 12 | % |
| |
(1) | Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. |
| |
(2) | The production associated with reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other reserve volumes are on a two-stream basis. |
| |
(3) | Excludes gathering and treating expense. |
| |
(4) | (1) Reflects calendar average daily spot market prices. |
Revenues
The following table is intended to reconcilereconciles the changechanges in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices.
|
| | | | | | | | | | | | | | | | |
| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Revenues for the year ended December 31, 2018 | |
| $530,898 |
| |
| $56,726 |
| |
| $— |
| |
| $587,624 |
|
Volume increase (decrease) | | 124,869 |
| | 15,683 |
| | 2,075 |
| | 142,627 |
|
Price increase (decrease) | | (22,660 | ) | | (36,019 | ) | | — |
| | (58,679 | ) |
Net increase (decrease) | | 102,209 |
| | (20,336 | ) | | 2,075 |
| | 83,948 |
|
Revenues for the year ended December 31, 2019 (1)(2) | |
| $633,107 |
| |
| $36,390 |
| |
| $2,075 |
| |
| $671,572 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Revenues for the year ended December 31, 2020 (1) | | $850,667 | | $51,866 | | $81,295 | | $983,828 | |
Volume increase (decrease) | | (47,659) | | (4,342) | | (4,878) | | (56,879) | |
Price increase (decrease) | | 713,217 | | 93,969 | | 117,444 | | 924,630 | |
Net increase (decrease) | | 665,558 | | 89,627 | | 112,566 | | 867,751 | |
Revenues for the year ended December 31, 2021 (1) | | $1,516,225 | | $141,493 | | $193,861 | | $1,851,579 | |
| | | | | | | | |
Percent of total revenues | | 82 | % | | 8 | % | | 10 | % | | |
| |
(1) | Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. |
| |
(2) | The revenues associated with production from reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other revenue is presented on a two-stream basis. |
Commodity Prices
The prices for oil, natural gas, and NGLs remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil, natural gas, and NGLs will affect the following aspects of our business:
our revenues, cash flows and earnings;
the amount(1) Excludes sales of oil and natural gas that we are economically ablepurchased from third parties and sold to produce;our customers.
our ability to attract capital to finance our operations and cost of the capital;
the amount we are allowed to borrow under the Credit Facility; and
the value of our oil and natural gas properties.
Oil revenue
ForRevenues for the year ended December 31, 2019, oil revenues2021, of $633.1 million$1.9 billion increased $102.2$867.8 million, or 19%88%, compared to revenues of $530.9$983.8 million for the year ended December 31, 2018.2020. The increase in oil revenue was primarily attributable to a 24%101% increase in production, partially offset by a 3% decrease in the average realized sales price which declinedrose to $54.27$53.06 per BblBoe from $56.22$26.45 per Bbl.Boe as well as revenue attributable to wells that were acquired in the Primexx Acquisition. The increase in production was comprised of 3.2 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells.
Natural gas revenue
Natural gas revenues decreased $20.3 million, or 36%, during the year ended December 31, 2019 to $36.4 million as compared to $56.7 million for the year ended December 31, 2018. The decrease primarily relates to an approximate 50% decrease in the average price realized which declined to $1.85 per Mcf from $3.67 per Mcf. The decreasesales price was partially offset by a 28% increase in natural gas volumes. The increase6% decrease in production, which was comprised of 4.6 Bcf attributableprimarily due to wells placed onthe divestitures that occurred during 2021 as well as normal production as a result of our horizontal drilling program,decline, partially offset by normal and expected declinesproduction resulting from our existing wells.
NGL revenue
We recognized NGL revenues of $2.1 milliondevelopmental activities during the year as a result ofwell as production from the recent Carrizoproperties acquired in the Primexx Acquisition.
Operating Expenses
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | Per | | | | Per | | Total Change | | Boe Change |
| | 2021 | | Boe | | 2020 | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Lease operating | | $203,141 | | | $5.82 | | | $194,101 | | | $5.22 | | | $9,040 | | | 5 | % | | $0.60 | | | 11 | % |
Production and ad valorem taxes | | 100,160 | | | 2.87 | | | 62,638 | | | 1.68 | | | 37,522 | | | 60 | % | | 1.19 | | | 71 | % |
Gathering, transportation and processing | | 80,970 | | | 2.32 | | | 77,309 | | | 2.08 | | | 3,661 | | | 5 | % | | 0.24 | | | 12 | % |
Depreciation, depletion and amortization | | 356,556 | | | 10.22 | | | 480,631 | | | 12.92 | | | (124,075) | | | (26 | %) | | (2.70) | | | (21 | %) |
General and administrative | | 50,483 | | | 1.45 | | | 37,187 | | | 1.00 | | | 13,296 | | | 36 | % | | 0.45 | | | 45 | % |
Impairment of evaluated oil and gas properties | | — | | | — | | | 2,547,241 | | | 68.48 | | | (2,547,241) | | | (100 | %) | | (68.48) | | | (100 | %) |
Merger, integration and transaction | | 14,289 | | | 0.41 | | | 28,482 | | | 0.77 | | | (14,193) | | | (50 | %) | | (0.36) | | | (47 | %) |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | | | Per | | | | Per | | Total Change | | Boe Change |
| | 2019 | | Boe | | 2018 | | Boe | | $ | | % | | $ | | % |
| | (In thousands, except per Boe and % amounts) |
Lease operating expenses | |
| $91,827 |
| |
| $6.09 |
| |
| $69,180 |
| |
| $5.76 |
| |
| $22,647 |
| | 33 | % | |
| $0.33 |
| | 6 | % |
Production taxes | | 42,651 |
| | 2.83 |
| | 35,755 |
| | 2.98 |
| | 6,896 |
| | 19 | % | | (0.15 | ) | | (5 | %) |
Depreciation, depletion and amortization | | 240,642 |
| | 15.95 |
| | 182,783 |
| | 15.21 |
| | 57,859 |
| | 32 | % | | 0.74 |
| | 5 | % |
General and administrative | | 45,331 |
| | 3.00 |
| | 35,293 |
| | 2.94 |
| | 10,038 |
| | 28 | % | | 0.06 |
| | 2 | % |
Merger and integration expenses | | 74,363 |
| | 4.93 |
| | — |
| | — |
| | 74,363 |
| | 100 | % | | 4.93 |
| | 100 | % |
Settled share-based awards | | 3,024 |
| | 0.20 |
| | — |
| | — |
| | 3,024 |
| | 100 | % | | 0.20 |
| | 100 | % |
Lease operating expenses.Operating Expenses. These are daily costs incurred to extract oil and natural gas and maintain our producing properties. Such costs also include maintenance, repairs, gas treating fees, salt water disposal, insurance and workover expenses related to our oil and natural gas properties.
Lease operating expenses for the year ended December 31, 20192021 increased by 33%5% to $91.8$203.1 million compared to $69.2$194.1 million for the same period of 2018,2020, primarily due to production volumes increasing 26%.operating expenses attributable to wells that were acquired in the Primexx Acquisition, partially offset by a reduction in certain operating expenses such as repairs and maintenance and equipment rentals. Lease operating expense per Boe for the year ended December 31, 20192021 increased to $6.09$5.82 compared to $5.76$5.22 for the same period of 20182020 primarily due to increased non-operated activity related to previous acquisitions and workovers.the wells that were acquired in the Primexx Acquisition, as discussed above, higher costs driven by the recent increase in inflation, as well as the distribution of fixed costs spread over lower production volumes.
Production taxes.and Ad Valorem Taxes. Production taxes include severanceFor the year ended December 31, 2021, production and ad valorem taxes increased 60% to $100.2 million compared to $62.6 million for the same period of 2020, which is primarily related to an 88% increase in total revenues which increased production taxes. In general, severanceThe impact of the increase in production taxes are based upon current year commodity prices whereasdescribed above was partially offset by a decrease in ad valorem taxes are based upon prior yeardue to lower property tax valuations for 2021 as a result of lower commodity prices. Severanceprices during 2020. Production and ad valorem taxes are paid on produced oil and natural gas based onas a percentage of total revenues from products sold at fixed rates establisheddecreased to 5.4% for the year ended December 31, 2021, as compared to 6.4% of total revenues for the same period of 2020, primarily due to lower property tax valuations for 2021 as discussed above.
Gathering, Transportation and Processing Expenses. Gathering, transportation and processing costs for the year ended December 31, 2021 increased by federal, state or local taxing authorities. In5% to $81.0 million compared to $77.3 million for the counties where oursame period of 2020, which was primarily related to new oil transportation agreements that were in place for the full year of 2021 as compared to a partial year in 2020, partially offset by a 6% decrease in production is located, we are also subject to ad valorem taxes, which are generally based onvolumes between the taxing jurisdictions’ valuationtwo periods as discussed above.
Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our oildepreciation, depletion and gas properties. We benefit from tax credits and exemptions in our various taxing jurisdictions where available.amortization for the periods indicated:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, | | |
| | 2021 | | 2020 | | | | |
| | Amount | | Per Boe | | Amount | | Per Boe | | | | | | | | |
| | (In thousands, except per Boe) | | | | | | | | |
DD&A of evaluated oil and gas properties | | $347,199 | | | $9.95 | | | $471,074 | | | $12.66 | | | | | | | | | |
Depreciation of other property and equipment | | 1,950 | | | 0.06 | | | 3,548 | | | 0.10 | | | | | | | | | |
Amortization of other assets | | 3,664 | | | 0.10 | | | 2,686 | | | 0.07 | | | | | | | | | |
Accretion of asset retirement obligations | | 3,743 | | | 0.11 | | | 3,323 | | | 0.09 | | | | | | | | | |
DD&A | | $356,556 | | | $10.22 | | | $480,631 | | | $12.92 | | | | | | | | | |
| | | | | | | | | | | | | | | | |
For the year ended December 31, 2019, production taxes increased 19%2021, DD&A decreased to $42.7$356.6 million compared to $35.8from $480.6 million for the same period of 2020. The decrease in 2018, due to an increase in severance taxes based on higher production volumes as well as an increase in ad valorem taxes due to a higher valuationDD&A was primarily the result of ourthe impairments of evaluated oil and gas properties by the taxing jurisdictions and previous acquisitions. On a per Boe basis, production taxes for the year ended December 31, 2019 decreased by 5% compared to the same period of 2018. Also, production taxesthat were recognized during 2020 as well as a percentageproduction decrease of total revenues for the year ended December 31, 2019 increased to 6.4% compared to 6.1% for the same period of 2018, due to higher ad valorem taxes as a result of higher valuations of our oil and gas properties during 2019.
Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years.
For the year ended December 31, 2019, DD&A increased 32% to $240.6 million from $182.8 million compared to the same period of 2018. The increase is primarily attributable to a 26% increase in production,6% as discussed above, and a 5% increase in our DD&A per Boe rate. For the year ended December 31, 2019, DD&A per Boe increased to $15.95 compared to $15.21 for the same period of 2018.above.
General and administrative, netAdministrative, Net of amounts capitalizedAmounts Capitalized (“G&A”). G&A for the year ended December 31, 20192021 increased to $45.3$50.5 million compared to $35.3$37.2 million for the same period of 2018. G&A2020, primarily due to an increase in the fair value of Cash-Settled RSU Awards and Cash SARs as a result of the significant increase in our stock price between the two periods as well as higher compensation costs.
Impairment of Evaluated Oil and Gas Properties. We did not recognize an impairment of evaluated oil and gas properties for the periods indicated includeyear ended December 31, 2021. Impairments of evaluated oil and gas properties of $2.5 billion were recognized for the following:year ended December 31, 2020, primarily due to declines in the 12-Month Average Realized Price of crude oil. See “Note 5 - Property and Equipment, Net” of the Notes to our Consolidated Financial Statements for further discussion.
|
| | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | $ Change | | % Change |
| | (In thousands, except % amounts) |
G&A | |
| $37,174 |
| |
| $28,710 |
| |
| $8,464 |
| | 29 | % |
Share-based compensation | | 7,043 |
| | 6,224 |
| | 819 |
| | 13 | % |
Fair value adjustments of cash-settled RSU awards | | 672 |
| | 359 |
| | 313 |
| | 87 | % |
Fair value adjustments of cash-settled stock appreciation rights | | 442 |
| | — |
| | 442 |
| | 100 | % |
Total G&A expenses | |
| $45,331 |
| |
| $35,293 |
| |
| $10,038 |
| | 28 | % |
Merger, Integration and integration expense.Transaction Expenses. For the year ended December 31, 2019,2021, we incurred merger, integration and transaction expenses of $14.3 million, which were associated with the Company incurred $74.4Primexx Acquisition, as compared to $28.5 million of expenses associated withfor 2020, which were related to the Carrizo Acquisition. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo.
Settled share-based awards. DuringPrimexx Acquisition and the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in $3.0 million recorded on the consolidated statements of operations.Carrizo Acquisition.
Other Income and Expenses
|
| | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | $ Change | | % Change |
| | (In thousands, except % amounts) |
Interest expense | |
| $81,399 |
| |
| $58,651 |
| |
| $22,748 |
| | 39 | % |
Capitalized interest | | (78,492 | ) | | (56,151 | ) | | (22,341 | ) | | 40 | % |
Interest expense, net of capitalized amounts | | 2,907 |
| | 2,500 |
| | 407 |
| | 16 | % |
(Gain) loss on derivative contracts | |
| $62,109 |
| |
| ($48,544 | ) | |
| $110,653 |
| | (228 | %) |
Interest expense, netExpense, Net of capitalized amounts.Capitalized Amounts. We finance a portionThe following table sets forth the components of our capital expenditures, acquisitions and working capital requirements with borrowings under our Credit Facility or with term debt. We incur interest expense that is affected by both fluctuations in interest rates and our financing decisions. We reflect interest paid to our lender in interest expense, net of capitalized amounts. In addition, weamounts for the periods indicated:
include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense. | | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | Change |
| | (In thousands) |
Interest expense on Senior Unsecured Notes | | $107,784 | | | $120,313 | | | ($12,529) | |
Interest expense on Second Lien Notes | | 43,791 | | | 9,188 | | | 34,603 | |
Interest expense on Credit Facility | | 31,647 | | | 45,912 | | | (14,265) | |
Amortization of debt issuance costs, premiums and discounts | | 18,309 | | | 7,325 | | | 10,984 | |
Other interest expense | | 128 | | | 190 | | | (62) | |
Capitalized interest | | (99,647) | | | (88,599) | | | (11,048) | |
Interest expense, net of capitalized amounts | | $102,012 | | | $94,329 | | | $7,683 | |
Interest expense, net of capitalized amounts, incurred during the year ended December 31, 20192021 increased $0.4$7.7 million to $2.9$102.0 million compared to $2.5$94.3 million for the same period of 2018.2020. The increase is primarily due to the issuance of the Second Lien Notes at the end of the third quarter of 2020 as well as amortization of the discount associated with those Second Lien Notes. These increases were partially offset by the reduction in Senior Unsecured Notes outstanding as a result of the exchange of Senior Unsecured Notes for Second Lien Notes which occurred during the fourth quarter of 2020, lower borrowings on the Credit Facility, and an increase in capitalized interest.
(Gain)Loss on extinguishment of debt.Derivative Contracts. During December 2019, in connection with the Carrizo Acquisition, we entered into a new credit facility and simultaneously terminated our prior credit facility. As a result of terminating the prior credit facility, we recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the prior credit facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Gain(loss)on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period.
For the year ended December 31, 2019, the net loss on derivative contracts was $62.1 million, compared to a $48.5 million net gain in 2018. The net gain (loss)(gain) loss on derivative contracts for the periods indicated includes the following:
|
| | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | Change |
| | (In thousands) |
Oil derivatives | | | | | | |
Net gain (loss) on settlements | |
| ($11,188 | ) | |
| ($27,510 | ) | |
| $16,322 |
|
Net gain (loss) on fair value adjustments | | (62,125 | ) | | 72,973 |
| | (135,098 | ) |
Total gain (loss) on oil derivatives | |
| ($73,313 | ) | |
| $45,463 |
| |
| ($118,776 | ) |
Natural gas derivatives | | | | | | |
Net gain (loss) on settlements | |
| $7,399 |
| |
| $238 |
| |
| $7,161 |
|
Net gain (loss) on fair value adjustments | | 1,490 |
| | 2,843 |
| | (1,353 | ) |
Total gain (loss) on natural gas derivatives | |
| $8,889 |
| |
| $3,081 |
| |
| $5,808 |
|
Contingent consideration arrangements | | | | | | |
Net gain (loss) on fair value adjustments | |
| $2,315 |
| |
| $— |
| |
| $2,315 |
|
Total gain (loss) on derivative contracts | |
| ($62,109 | ) | |
| $48,544 |
| |
| ($110,653 | ) |
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | Change |
| | (In thousands) |
(Gain) loss on oil derivatives | | $429,156 | | | ($48,031) | | | $477,187 | |
(Gain) loss on natural gas derivatives | | 33,621 | | | 14,883 | | | 18,738 | |
(Gain) loss on NGL derivatives | | 6,768 | | | 2,426 | | | 4,342 | |
(Gain) loss on contingent consideration arrangements | | (2,635) | | | 2,976 | | | (5,611) | |
(Gain) loss on September 2020 Warrants liability | | 55,390 | | | 55,519 | | | (129) | |
(Gain) loss on derivative contracts | | $522,300 | | | $27,773 | | | $494,527 | |
See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.
Income tax expense. (Gain) LossWe useon Extinguishment of Debt. During November 2021, in connection with the asset and liability methodexchange of accounting$197.0 million of our Second Lien Notes for income taxes, under5.5 million shares of our common stock, we recorded a loss on extinguishment of debt of $43.4 million, which deferred tax assets and liabilities are recognized forconsisted of the future tax consequencesnotional amount of (1) temporary differences betweencommon stock issued less the financial statement carrying amounts andaggregate principal amount of the tax bases of existing assets and liabilities and (2) operating loss and tax credit carryforwards. Deferred income tax assets and liabilities are based on enacted tax rates applicable to the future period when those temporary differences are expected to be recovered or settled. The effectSecond Lien Notes exchanged, net of a change in tax ratespro-rata write-off of associated unamortized discount of $16.9 million and fees incurred. Additionally, during July 2021, we redeemed all of our 6.25% Senior Notes and recorded a gain on deferred tax assets and liabilities is recognized in income in the period the rate change is enacted. When appropriate based on our analysis, we record a valuation allowance for deferred tax assets when it is more likely than not that the deferred tax assets will not be realized.
The Company recorded income tax expenseextinguishment of $35.3debt of $2.4 million, for the year ended December 31, 2019 compared to $8.1 million for the same period of 2018. The change in income tax iswhich was primarily related to writing off the changeremaining unamortized premium associated with the 6.25% Senior Notes.
During November 2020, in connection with the Company’s tax position in the current period, as the Company no longer maintains a valuation allowance against its deferred tax assets. Current period income tax expense is comprisedexchange of both deferred federal and state income tax expense.
Preferred stock dividends. Holders$389.0 million of our Preferred Stock were entitled to receive, when, as and if declared by our Board of Directors, out of funds legally availableSenior Unsecured Notes for the paymentSecond Lien Notes, we recorded a gain on extinguishment of dividends, cumulative cash dividends at a ratedebt of 10% per annum$170.4 million, which consisted of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share).carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the Second Lien Notes issued, net of the associated debt discount of $9.1 million, which was based on the Second Lien Notes’ allocated fair value on the exchange date.
Preferred stock dividends for the year ended December 31, 2019 decreased 45% to $4.0 million compared to $7.3 million in 2018. The decrease is attributable to the redemption of our preferred stock in July 2019. See “Note 117 – Stockholders’ Equity”Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Loss on redemptionIncome Tax Expense. We recorded income tax expense of preferred stock. As$0.2 million for the year ended December 31, 2021 compared to $122.1 million for the same period of 2020. Since the second quarter of 2020, we have concluded that it is more likely than not that the net deferred tax assets will not be realized and have recorded a resultfull valuation allowance against our deferred tax assets, which still remained as of the redemption of our Preferred Stock mentioned above, we recognized an $8.3 million loss due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value.December 31, 2021. See “Note 1112 – Stockholders’ Equity”Income Taxes” of the Notes to our Consolidated Financial Statements for additional information. information regarding the valuation allowance.
Liquidity and Capital Resources
2022 Capital Budget and Funding Strategy.Our primary uses2022 Capital Budget has been established at $725.0 million, with over 85% allocated towards development in the Permian with the balance towards development in the Eagle Ford. Because we are the operator of a high percentage of our properties, we can control the amount and timing of our capital have historically beenexpenditures. We plan to execute a moderated capital expenditure program through reduced reinvestment rates and balanced capital deployment for a more consistent cash flow generation and will be focused to further enhance our multi-zone, scaled development program to drive capital efficiency. See “Items 1 and 2. Business and Properties - Capital Budget” for additional details.
The following table is a summary of our 2021 capital expenditures (1):
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Three Months Ended | | Year Ended |
| March 31, 2021 | | June 30, 2021 | | September 30, 2021 | | December 31, 2021 | | December 31, 2021 |
| (In millions) |
Operational capital | $95.6 | | $138.3 | | $115.0 | | $159.7 | | $508.6 |
Capitalized interest | 24.0 | | 23.9 | | 26.1 | | 25.6 | | 99.6 |
Capitalized G&A | 11.2 | | 12.1 | | 10.4 | | 13.7 | | 47.4 |
Total | $130.8 | | $174.3 | | $151.5 | | $199.0 | | $655.6 |
(1) Capital expenditures, presented on an accrual basis, includes drilling, completions, facilities, and equipment, and excludes land, seismic, and asset retirement costs.
We believe that existing cash and cash equivalents, any positive cash flows from operations and available borrowings under our revolving credit facility will be sufficient to support working capital, capital expenditures and other cash requirements for at least the next 12 months and, based on our current expectations, for the acquisition, development,foreseeable future thereafter. Our future capital requirements, both near-term and exploration of oil and natural gas properties. Our capital program could vary depending uponlong-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestituressuccess of oil and gas properties,drilling programs, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition
of leases with drilling commitments, and other factors.
Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions. As we pursue reserves and production growth, we We regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements.
In addition, depending upon our actual and anticipated sources and uses of liquidity, prevailing market conditions and other factors, we may, from time to time, seek to retire or repurchase our outstanding debt or equity securities through cash purchases in the open market or through privately negotiated transactions or otherwise. The amounts involved in any such transactions, individually or in aggregate, may be material. During 2021, to help manage our future financing cash outflows and liquidity position, we completed the exchange of $197.0 million of aggregate principal amount of our 9.00% Second Lien Senior Secured Notes for 5.5 million shares of our common stock, which reduced the long-term debt balance in our consolidated balance sheets and also reduced future interest payments.
We may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth or enter into joint venture agreements, provided we are able to divest such assets or enter into joint venture agreements on terms that are acceptable to us. During 2021, we sold certain non-core assets in the Delaware Basin, Eagle Ford Shale and Midland Basin for combined net proceeds of $181.8 million, which were used to repay borrowings outstanding under the Credit Facility.
Overview of Cash Flow Activities. For the year ended December 31, 2019,2021, cash and cash equivalents decreased $2.7$10.3 million to $13.3$9.9 million compared to $16.1$20.2 million at December 31, 2018.2020.
| | | Years Ended December 31, | | Years Ended December 31, |
| 2019 | | 2018 | | 2021 | | 2020 |
| (In thousands) | | (In thousands) |
Net cash provided by operating activities |
| $476,316 |
| |
| $467,654 |
| Net cash provided by operating activities | $974,143 | | | $559,775 | |
Net cash used in investing activities | (388,389 | ) | | (1,324,057 | ) | Net cash used in investing activities | (876,400) | | | (529,883) | |
Net cash provided by (used in) financing activities | (90,637 | ) | | 844,459 |
| |
Net cash used in financing activities | | Net cash used in financing activities | (108,097) | | | (22,997) | |
Net change in cash and cash equivalents |
| ($2,710 | ) | |
| ($11,944 | ) | Net change in cash and cash equivalents | ($10,354) | | | $6,895 | |
Operating activities.Activities. Net cash provided by operating activities was $476.3$974.1 million and $467.7$559.8 million for the years ended December 31, 20192021 and 2018,2020, respectively. The changeincrease in operating activities was predominantlyprimarily attributable to the following:
•An increase in revenue due to higher production volumes, offset by a decreasean increase in realized pricing; and
An offsetting increase in operating expenses as a result of higher production volumes;
An offsetting increase in cash G&A expense due to increase personnel costs, and;
•Changes related to timing of working capital payments and receipts.receipts; offset by
Production, realized prices, and operating expenses are discussed below•Increase in Results of Operations. See “Note 8 – Derivative Instruments and Hedging Activities”and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statementscash paid for a reconciliation of the components of the Company’scommodity derivative contracts and disclosures related to derivative instruments including their composition and valuation.settlements.
Investing activities.Activities. Net cash used in investing activities was $388.4$876.4 million and $1,324.1$529.9 million for the years ended December 31, 20192021 and 2018,2020, respectively. The changeincrease in investing activities was primarily attributable to the following:
| |
• | A $285.4 million increase in proceeds received from the sale of non-core assets as compared to the year ended December 31, 2018.
|
A $676.5 million decrease in acquisitions.
A $29.4$480.8 million increase in capital expendituresacquisitions due to increased activity from our 2019 development program, focused on multi-well pads, as well as additional investmentsthe Primexx acquisition; offset by
•A decrease in facilities and infrastructure.
Our investing activities, on a cash basis, include the following for the periods indicated: |
| | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | $ Change |
| | (In thousands) |
Operational expenditures | |
| $520,614 |
| |
| $537,514 |
| |
| ($16,900 | ) |
Seismic, leasehold and other | | 8,984 |
| | 8,555 |
| | 429 |
|
Capitalized general and administrative costs | | 31,612 |
| | 24,383 |
| | 7,229 |
|
Capitalized interest | | 79,330 |
| | 40,721 |
| | 38,609 |
|
Total capital expenditures (1) | |
| $640,540 |
| |
| $611,173 |
| |
| $29,367 |
|
| | | | | | |
Acquisitions | |
| $42,266 |
| |
| $718,793 |
| |
| ($676,527 | ) |
Proceeds from the sale of assets | | (294,417 | ) | | (9,009 | ) | | (285,408 | ) |
Additions to other assets | | — |
| | 3,100 |
| | (3,100 | ) |
Total investing activities | |
| $388,389 |
| |
| $1,324,057 |
| |
| ($935,668 | ) |
| |
(1) | Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date. |
On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year ended December 31, 2019 were $506.1 million. Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the year ended December 31, 2019 were $629.7 million.
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See “Note 4 – Acquisitions and Divestitures” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information on significant acquisitions and drilling rig leases.expenditures.
Financing activities.Activities. We finance a portion of our capital expenditures, acquisitions and working capital requirements with borrowings under our credit facility, term debt and equity offerings. For the year ended December 31, 2019,2021, net cash used in financing activities was $90.6$108.1 million compared to net cash provided by financing activities of $844.5$23.0 million during the same period of 2018.2020. The changeincrease in net cash provided by (used in)used in financing activities was primarily attributable to the following:
Repayment of Carrizo’s credit facility and funded the redemption of preferred stock upon closing the Carrizo Acquisition.
•Redemption of Preferred Stock for approximately $73.0 million in 2019.
Completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds of approximately $288.0 million in 2018.
Issuance of Senior Notes due 2026, as defined below, for $394.0 million in net proceeds in 2018 in conjunction with the Delaware Asset Acquisition.
Net cash provided by (used in) financing activities includes the following for the periods indicated:
|
| | | | | | | | | | | |
| Years Ended December 31, |
| 2019 | | 2018 | | $ Change |
| (In thousands) |
Net borrowings on Credit Facility |
| $1,560,400 |
| |
| $175,000 |
| |
| $1,385,400 |
|
Repayment of Prior Credit Facility | (475,400 | ) | | — |
| | (475,400 | ) |
Repayment of Carrizo credit facility | (853,549 | ) | | — |
| | (853,549 | ) |
Repayment of Carrizo preferred stock | (220,399 | ) | | — |
| | (220,399 | ) |
Issuance of 6.375% Senior Notes due 2026 | — |
| | 400,000 |
| | (400,000 | ) |
Issuance of common stock | — |
| | 287,988 |
| | (287,988 | ) |
Payment of preferred stock dividends | (3,997 | ) | | (7,295 | ) | | 3,298 |
|
Redemption of preferred stock | (73,017 | ) | | — |
| | (73,017 | ) |
Payment of deferred financing costs | (22,480 | ) | | (9,430 | ) | | (13,050 | ) |
Tax withholdings related to restricted stock units | (2,195 | ) | | (1,804 | ) | | (391 | ) |
Net cash provided by (used in) financing activities |
| ($90,637 | ) | |
| $844,459 |
| |
| ($935,096 | ) |
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information about the Company’s debt. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information about the Company’s equity offerings and the redemption of our Preferred Stock.
Senior Secured Credit Facility. Upon consummation of the Merger on December 20, 2019, the Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) and entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such timein July 2021; and (ii) July 2, 2024 if
•Repayments on the 6.125%Credit Facility; offset by
•The issuance of $650.0 million of 8.00% Senior Notes are outstanding at such time), when thein July 2021
Credit Facility. As of December 31, 2021, our Credit Facility matures and any outstanding borrowings are due. Thehad a maximum credit amount under the Credit Facility isof $5.0 billion.billion, a borrowing base and elected commitment amount of $1.6 billion, with borrowings outstanding of $785.0 million at a weighted-average interest rate of 2.65%, and letters of credit outstanding of $24.0 million. The borrowing base under the Credit Facilitycredit agreement is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. TheOn November 1, 2021, we entered into the fifth amendment to our credit agreement governing the Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which, hare not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.
As of December 31, 2019,among other things, reaffirmed the borrowing base under the Credit Facility was $2.5 billion, with anand elected commitment amount of $2.0$1.6 billion as a result of the fall 2021 scheduled redetermination.
Our Credit Facility contains certain covenants including restrictions on additional indebtedness, payment of cash dividends and borrowings outstandingmaintenance of $1.3 billion. The weighted average interest ratecertain financial ratios. Under the Credit Facility, we currently must maintain the following financial covenants determined as of the last day of the quarter: (1) commencing on March 31, 2020 and for each quarter ending on or prior to December 31, 2021, a Secured Leverage Ratio of no more than 3.00 to 1.00; (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio of no more than 4.00 to 1.00; and (3) a Current Ratio of not less than 1.00 to 1.00. We were in compliance with these covenants at December 31, 2021.
Second Lien Note Exchange.On November 5, 2021, we closed on the agreement with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of our outstanding borrowings was 3.56%. Second Lien Notes, for a notional amount of approximately $223.1 million of our common stock, which equated to 5.5 million shares.
The Company also had $17.78.00% Senior Notes and Redemption of 6.25% Senior Notes. On July 6, 2021, we issued $650.0 million aggregate principal amount of 8.00% Senior Notes due 2028 in lettersa private placement for proceeds of creditapproximately $638.1 million, net of underwriting discounts and commissions and offering costs. The 8.00% Senior Notes mature on August 1, 2028 and interest is payable semi-annually each February 1 and August 1, commencing on February 1, 2022. On June 21, 2021, we delivered a redemption notice with respect to all $542.7 million of our outstanding 6.25% Senior Notes due 2023, which became redeemable on July 21, 2021. We used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of our outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility as of December 31, 2019.Facility.
Effective April 5, 2018, the Company entered into the first amendment to the Prior Credit Facility, as defined below, which (1) increased the borrowing base to $825.0 million, (2) increased the elected commitment amount to $650.0 million, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023.
Effective September 27, 2018, the Company entered into the second amendment to the Prior Credit Facility, which (1) increased the borrowing base to $1.1 billion, (2) increase the elected commitment amount to $850.0 million, and (3) amended various covenants and terms to reflect current market trends.
Each of the first and second amendments to the Prior Credit Facility were terminated in conjunction with the termination of the Prior Credit Facility.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.information on our long-term debt.
Senior Notes
Material Cash Requirements
Upon consummationAs of the Merger,December 31, 2021, we became successor-in-interest to the indenture governing Carrizo’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) have financial obligations associated with our outstanding long-term debt, including interest payments and the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The assumed Senior Notes are described below along with Callon’s legacy Senior Notes.
6.375% Senior Notes. On June 7, 2018, we issued $400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, were used to fund a portion of the Delaware Asset Acquisition, described below. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.
6.125% Senior Notes. On October 3, 2016, we issued $400.0 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually each April 1 and October 1. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. On May 19, 2017, we issued an additional $200.0 million aggregate principal amount of 6.125% Senior Notes which, with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes, are treated as a single class of notes under the indenture.
8.25% Senior Notes. The 8.25% Senior Notes have an aggregate principal amount of $250.0 million, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, we may, at our option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest.
6.25% Senior Notes. The 6.25% Senior Notes have an aggregate principal amount of $650.0 million, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. We may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.
repayments. See “Note 7 -– Borrowings” of the Notes to our Consolidated Financial Statements for additional information about our Senior Notes.
Preferred Stock. Holdersfurther discussion of the Preferred Stock were entitled to receive, when, ascontractual commitments under our debt agreements, including the timing of principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and if declared by the Boardtransportation service agreements, and estimates of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million and $7.3 million for the years ended December 31, 2019 and 2018, respectively.
On June 18, 2019, we announced we had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). We recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock.
After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.
future asset retirement obligations. See “Note 11 - Stockholders’ Equity”14 – Asset Retirement Obligations” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional discussion.details.
2020 Capital Plan and Outlook
Our 2020 Capital Budget has been established at $975.0 million, which includes running an average of eight to nine drilling rig sand an average of three completion crews. Approximately 10-15% ofWe estimate that the 2020 Capital Budget is comprised of infrastructure and facilities capital. As partcombination of our 2020 operated horizontal drilling program, we expectsources of capital, as discussed above, will continue to drill approximately 165 gross operated wellsbe adequate to fund our short- and complete approximately 160 gross operated wells. We currently expect to direct the majority of our 2020 Capital Budget towards opportunities in the Permian Basin. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us.long-term contractual obligations.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.
Contractual ObligationsOther Commitments
The following table includes our current contractual obligationsoil sales contracts and purchase commitmentsfirm transportation agreements as of December 31, 2019:
|
| | | | | | | | | | | | | | | | | | | | |
| | Payments due by Period |
| | < 1 Year | | Years 2 - 3 | | Years 4 - 5 | | > 5 Years | | Total |
| | (In thousands) |
6.25% Senior Notes (1) | |
| $— |
| |
| $— |
| |
| $650,000 |
| |
| $— |
| |
| $650,000 |
|
6.125% Senior Notes (1) | | — |
| | — |
| | 600,000 |
| | — |
| | 600,000 |
|
8.25% Senior Notes (1) | | — |
| | — |
| | — |
| | 250,000 |
| | 250,000 |
|
6.375% Senior Notes (1) | | — |
| | — |
| | — |
| | 400,000 |
| | 400,000 |
|
Credit Facility (2) | | — |
| | — |
| | 1,285,000 |
| | — |
| | 1,285,000 |
|
Interest expense and other fees related to debt commitments (3) | | 172,821 |
| | 345,642 |
| | 283,218 |
| | 71,625 |
| | 873,306 |
|
Drilling rig leases (4) | | 33,441 |
| | 3,249 |
| | — |
| | — |
| | 36,690 |
|
Operating leases | | 12,423 |
| | 12,762 |
| | 8,319 |
| | 17,902 |
| | 51,406 |
|
Delivery commitments (5) | | 9,563 |
| | 24,417 |
| | 23,970 |
| | 39,298 |
| | 97,248 |
|
Produced water disposal commitments (6) | | 14,947 |
| | 26,901 |
| | 5,957 |
| | 1,840 |
| | 49,645 |
|
Asset retirement obligations (7) | | 468 |
| | 314 |
| | 565 |
| | 48,386 |
| | 49,733 |
|
Other commitments | | 1,240 |
| | 844 |
| | 159 |
| | — |
| | 2,243 |
|
Total contractual obligations | |
| $244,903 |
| |
| $414,129 |
| |
| $2,857,188 |
| |
| $829,051 |
| |
| $4,345,271 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
Type of Commitment (1) | | Region | | Execution Date | | Start Date | | End Date | | Committed Volumes (Bbls/d) |
Oil sales contract | | Permian | | October 2021 | | January 2022 | | December 2022 | | 7,500 |
Oil sales contract | | Permian | | July 2019 | | August 2021 | | July 2026 | | 5,000 |
Oil sales contract | | Permian | | June 2019 | | January 2020 | | December 2024 | | 10,000 |
Oil sales contract | | Permian | | August 2018 | | April 2020 | | March 2022 | | 15,000 |
Firm transportation agreement (2)(3) | | Permian | | June 2019 | | August 2020 | | July 2030 | | 10,000 |
Firm transportation agreement (2) | | Permian | | August 2018 | | April 2020 | | March 2027 | | 15,000 |
| |
(1) | Includes the outstanding principal amount only. |
| |
(2) | The Credit Facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information. |
| |
(3) | Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of December 31, 2019, at the applicable commitment fee rate. |
| |
(4) | Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2019. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information related to the Company’s drilling rig leases. |
| |
(5) | Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas. |
| |
(6) | Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water. |
| |
(7) | Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “Note 14 – Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information. |
Other commitments
In July 2019, the Company executed a crude oil sales contract that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term(1)For each of the agreement and will apply applicable tariff rates to those quantities. Barrelscommitments shown in the table above, the committed barrels may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf. We expect to fulfill these delivery commitments with our existing production or through the purchases of third-party commodities.
In June 2019,(2)Each of the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originatesagreements shown in Midland, Texas and terminates in Houston, Texas. Subjectthe table above grant us access to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our quantitiesCoast.
(3)The committed that average 10,000 Bbls per dayvolumes shown in the table above for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.
In August 2018, the Company executed athis particular firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oilare average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes under long-term agreements from our properties in Howardare 7,500 Bbls/d, 10,000 Bbls/d and Ward counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.12,500 Bbls/d, respectively.
In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.
Summary of Critical Accounting PoliciesEstimates
The following summarizesFor discussion regarding our critical accounting policies. See a complete list of significant accounting policies, insee “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements.
Use of Estimates
The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of provedevaluated oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other
significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Oil and natural gas propertiesNatural Gas Properties
Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred.
Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and proved reserves in which case a gain or loss is recognized. For the years ended December 31, 2019 and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship.
Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method converting natural gas to barrels of oil equivalent atwhereby the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortizationdepletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such amortizationdepletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.
Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assesses properties on an individual basis or as Each quarter, a group and considers the following factors, among others,full cost ceiling test is performed to determine if these costs have been impaired: exploration program and intentwhether an impairment to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded toour evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.
Write-down of Evaluated Properties
At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures toshould be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.recorded.
The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price of oil, NGLs, and natural gas, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment.
Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 as well as impairments of evaluated oil and 2018natural gas properties are summarized in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Impairment of evaluated oil and natural gas properties (In thousands) | $— | | $2,547,241 | | $— |
Beginning of period 12-Month Average Realized Price ($/Bbl) | $37.44 | | $53.90 | | $58.40 |
End of period 12-Month Average Realized Price ($/Bbl) | $65.44 | | $37.44 | | $53.90 |
Percent increase (decrease) in 12-Month Average Realized Price | 75 | % | | (31 | %) | | (8 | %) |
The process of estimating proved oil and gas reserves requires that our independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. Additionally, operating costs, production and ad valorem taxes, and future development costs are estimated based on current costs. A significant change to our estimated volumes of oil and gas reserves as well as changes to the estimates of prices and costs could have an impact on the depletion rate calculation as well as the estimated future net revenues used in the cost center ceiling. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.”
|
| | | | | | | |
| Years Ended December 31, |
| 2019 | | 2018 |
Write-down of evaluated oil and natural gas properties (In thousands) | $— | | $— |
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period | $58.40 | | $49.48 |
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period | $53.90 | | $58.40 |
Crude Oil 12-Month Average Realized Price percentage increase (decrease) | (8%) | | 18% |
The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 20192021 cost center ceiling to changes in 12-month average benchmark crude oil and natural gas prices underlying the 12-Month Average Realized Prices. The sensitivity analysis is as of December 31, 20192021 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 20192021 that may require revisions to estimates of proved reserves. See also Part I, “Item 1A. Risk Factors—If oil and natural gas prices remain depressed for extended periods of time, we couldmay be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.”
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| | | | | | | | |
| | 12-Month Average Realized Prices | | Excess of cost center ceiling over net book value, less related deferred income taxes | | Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes |
Full Cost Pool Scenarios | | Crude Oil ($/Bbl) | | Natural Gas ($/Mcf) | | (In millions) | | (In millions) |
December 31, 2019 Actual | | $53.90 | | $1.55 | | $631 | | |
| | | | | | | | |
Crude Oil and Natural Gas Price Sensitivity | | | | | | | | |
Crude Oil and Natural Gas +10% | | $59.47 | | $1.85 | | $1,456 | | $825 |
Crude Oil and Natural Gas -10% | | $48.33 | | $1.25 | | ($369) | | ($1,000) |
| | | | | | | | |
Crude Oil Price Sensitivity | | | | | | | | |
Crude Oil +10% | | $59.47 | | $1.55 | | $1,378 | | $747 |
Crude Oil -10% | | $48.33 | | $1.55 | | ($270) | | ($901) |
| | | | | | | | |
Natural Gas Price Sensitivity | | | | | | | | |
Natural Gas +10% | | $53.90 | | $1.85 | | $702 | | $71 |
Natural Gas -10% | | $53.90 | | $1.25 | | $546 | | ($85) |
We estimate that the first quarter of 2020 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no write-down of evaluate oil and gas properties. This estimate of the first quarter of 2020 cost center ceiling test is based on an estimated 12-Month Average Realized Price of crude oil of $56.09 per barrel as of March 31, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price.
Both of these estimates assume that all other inputs and assumptions are as of December 31, 2019, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to December 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.
Estimatingreserves and present value of estimated future net cash flows
Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include:
the prices at which the Company can sell its production in the future. Oil, natural gas, and NGL prices are volatile, but we are required to assume that they remain constant, using the 12-Month Average Realized Price. In general, higher oil, natural gas, and NGL prices will increase quantities of estimated proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and
the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated proved reserves and the present value of estimated future net cash flows, while decreases in costs will increase such amounts.
Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated proved reserves for the Company’s properties that have relatively short productive lives. If oil, natural gas, and NGL prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of proved reserves.
In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.”
Assetretirementobligations
We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information.
Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations. | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 12-Month Average Realized Prices | | Excess (deficit) of cost center ceiling over net book value, less related deferred income taxes | | Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes |
Full Cost Pool Scenarios | | Crude Oil ($/Bbl) | | Natural Gas ($/Mcf) | | (In millions) | | (In millions) |
December 31, 2021 Actual | | $65.44 | | $3.31 | | $2,905 | | |
| | | | | | | | |
Crude Oil and Natural Gas Price Sensitivity | | | | | | | | |
Crude Oil and Natural Gas +10% | | $72.10 | | $3.68 | | $3,783 | | $878 |
Crude Oil and Natural Gas -10% | | $58.78 | | $2.95 | | $2,027 | | ($878) |
| | | | | | | | |
Crude Oil Price Sensitivity | | | | | | | | |
Crude Oil +10% | | $72.10 | | $3.31 | | $3,711 | | $806 |
Crude Oil -10% | | $58.78 | | $3.31 | | $2,099 | | ($806) |
| | | | | | | | |
Natural Gas Price Sensitivity | | | | | | | | |
Natural Gas +10% | | $65.44 | | $3.68 | | $2,977 | | $72 |
Natural Gas -10% | | $65.44 | | $2.95 | | $2,833 | | ($72) |
Derivative Instruments
To manage oil and natural gasWe use commodity derivative instruments to mitigate the effects of commodity price risk onvolatility for a portion of our planned futureforecasted sales of production we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60%achieve a more predictable level of our projected production volumes in any given year.cash flow. We do not use these instruments for speculative or trading purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price.
Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding our derivatives instruments and their fair values, see “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial StatementsStatements.
Our financial condition and results of operations can be significantly impacted by changes in the market value of our derivative instruments as a result of the volatility of oil and gas prices. See “Part II, Item 7A. Quantitative and Qualitative Disclosures Aboutabout Market Risk - Commodity Price Risk”. for the impact on the fair values of our derivative instruments assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2021.
Income taxesTaxes
The amount of income taxes recorded requires interpretations of complex rules and regulations of federal and state tax jurisdictions. We recognize current tax expense based on estimated taxable income for the current period and the applicable statutory tax rates. We routinely assess potential uncertain tax positions and, if required, estimate and establish accruals for such amounts. We have recognized deferred tax assets and liabilities for temporary differences, operating losses and other tax carryforwards. We routinely assess
Management monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that our net deferred tax assets will be utilized prior to their expiration. A significant item of objective negative evidence considered was the cumulative historical three year pre-tax loss and reducea net deferred tax asset position at December 31, 2021, driven primarily by impairments of evaluated oil and gas properties recognized beginning in the second quarter of 2020 and continuing through the fourth quarter of 2020, which limits the ability to consider other subjective evidence such assets by a valuation allowance ifas our potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, we deemconcluded that it is more likely than not that some portion or all of the net deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance asAs of December 31, 20192021, a valuation allowance continues to be in place which reduces the net deferred tax assets to zero.
We will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until we can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead us to conclude that it is more likely than not our net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and 2018.taxable events that could result from one or more transactions. The valuation allowance does not preclude us from utilizing the tax attributes if we recognize taxable income. As long as we continue to conclude that the valuation allowance against our net deferred tax assets is necessary, we will have no significant deferred income tax expense or benefit. See “Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regardingdiscussion.
Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income taxes.is subject to various limitations under the Internal Revenue Code of 1986, as amended (the “Code”). The utilization of such carryforwards may be limited upon the occurrence of certain ownership changes, including the purchase or sale of stock by 5% shareholders and the offering of stock by us during any three-year period resulting in an aggregate change of more than 50% in the beneficial ownership of Callon. In the event of an ownership change, Section 382 of the Code (“Section 382”) imposes an annual limitation on the amount of our taxable income that can be offset by these carryforwards. The limitation is generally equal to the product of (i) the fair market value of the equity of Callon multiplied by (ii) a percentage approximately equivalent to the yield on long-term tax exempt bonds during the month in which an ownership change occurs. In addition, the limitation is increased if there are recognized built-in gains during any post-change year, but only to the extent of any net unrealized built-in gains inherent in the assets sold. Due to the issuance of common stock associated with the Carrizo Acquisition, we incurred a cumulative ownership change and as such, our NOLs prior to the acquisition are subject to an annual limitation under Section 382.
Recently Adopted and Recently Issued AccountingStandardsUpdates Pronouncements
See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board.
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2019.
ITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.
Commodity price riskPrice Risk
The Company’sOur revenues are derived from the sale of itsour oil, and natural gas, and NGL production. The prices for oil, and natural gas, and NGLs remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions,government actions, economic conditions, and government actions. weather conditions.
From time to time, the Company enterswe enter into derivative financial instruments to manage oil, and natural gas and NGL price risk, related both to NYMEX benchmark prices and regional basis differentials. The total volumes which we hedge through use of our derivative instruments varies from period to period; however,period and takes into account our view of current and future market conditions in order to provide greater certainty of cash flows to meet our debt service costs and capital program. We generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.
As of December 31, 2019, for the full year of 2020, the Company had 18,017,900 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also had 8,476,700 Bbls of WTI Midland-Cushing oil basis hedges and 1,439,205 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the full year of 2020, the Company had 7,320,000 MMBtus of fixed price NYMEX natural gas hedges and 21,596,000 MMBtus of Waha natural gas basis hedges. See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts as of December 31, 2019.
The CompanyWe may utilize fixed price swaps, which reduce the Company’sour exposure to decreases in commodity prices, and limitbut limits the benefit the Companywe might otherwise have received from any increases in commodity prices. Swap contracts may also be enhanced by the simultaneous sale of call or put options to effectively increase the effective swap price as a result of the receipt of premiums from the option sales.
The CompanyWe also may utilize price collars to reduce the risk of changes in oil and natural gas prices. Under these arrangements, no payments are due by either party as long as the applicable market price is above the floor price (purchased put option) and below the ceiling price (sold call option) set in the collar. If the price falls below the floor, the counter-partycounterparty to the collar pays the difference to the Company,us, and if the price rises above the ceiling, the counterparty receives the difference from the Company.us. Additionally, the Companywe may sell put (or call) options at a price lower than the floor price (or higher than the ceiling price) in conjunction with a collar (three-way collar) and use the proceeds to increase either or both the floor or ceiling prices. In a three-way collar, to the extent that realized prices are below the floor price of the sold put option (or above the ceiling price of the sold call option), the Company’sour net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.
The CompanyWe may purchase put and call options, which reduce the Company’sour exposure to decreases in oil and natural gas prices while allowing realization of the full benefit from any increases in oil and natural gas prices. If the price falls below the floor, the counterparty pays the difference to the Company.us.
The Company entersWe enter into these various agreements from time to time to reduce the effects of volatile oil, and natural gas and NGL prices and doesdo not enter into derivative transactions for speculative or trading purposes. Presently, none of the Company’sour derivative positions are designated as hedges for accounting purposes.
The Company isfollowing table sets forth the fair values as of December 31, 2021, excluding deferred premium obligations, as well as the impact on the fair values assuming a 10% increase and decrease in the underlying forward oil and gas price curves as of December 31, 2021:
| | | | | | | | | | | | | | | | | | | | | | | | | | |
| | Year Ended December 31, 2021 |
| | Oil | | Natural Gas | | NGLs | | Total |
| | (In thousands) |
Fair value (liability) asset as of December 31, 2021 (1) | | ($132,896) | | | ($3,203) | | | $890 | | | ($135,209) | |
| | | | | | | | |
Impact of a 10% increase in forward commodity prices | | ($236,007) | | | ($7,186) | | | ($1,664) | | | ($244,857) | |
Impact of a 10% decrease in forward commodity prices | | ($41,019) | | | $666 | | | $3,445 | | | ($36,908) | |
(1)Spot prices for crude, natural gas and NGLs were $75.21, $3.73 and $39.13, respectively, as of December 31, 2021.
Interest Rate Risk
We are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2019, the Company2021, we had $1.3 billion$785.0 million outstanding under the Credit Facility with a weighted average interest rate of 3.56%2.65%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net incomeinterest expense of approximately $12.9$7.9 million, based on the balance outstanding atas of December 31, 2019.2021. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on the Company’s interest rates on our Credit Facility.
Counterparty and customer credit riskCustomer Credit Risk
The Company’sOur principal exposures to credit risk are through receivables from the sale of our oil, and natural gas and NGL production, joint interest receivables and receivables resulting from derivative financial contracts.
The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2019,2021, four purchasers each accounted for more than 10% of our revenue: Rio Energy International, Inc. (26%); Enterprise Crude Oil, LLC (19%); Plains Marketing, L.P. (15%); and Shell Trading Company (10%).revenue. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At December 31, 2019We are generally paid by our total receivables frompurchasers within 30 to 90 days after the salemonth of our oilproduction and natural gas production were approximately $165.3 million.
currently do not believe that we have a risk of not collecting.
Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2019, ourWe generally have the right to withhold future revenue distributions to recover past due receivables from joint interest receivables were approximately $42.5 million.owners.
Our oilSee “Note 8 - Derivative Instruments and natural gas commodity derivative arrangements expose usHedging Activities” of the Notes to our Consolidated Financial Statements for discussion of counterparty credit risk in the event of nonperformance by counterparties. Most of the counterparties on our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”)associated with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At December 31, 2019, we had a net commodity derivative liability position of $24.8 million.arrangements.
ITEM 8. Financial Statements and Supplementary Data
| | | | | |
| |
| Page |
Reports of Independent Registered Public Accounting Firm (PCAOB ID Number 248) | |
Consolidated Balance Sheets as of December 31, 20192021 and 20182020 | |
Consolidated Statements of Operations for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | |
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | |
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 20182021, 2020 and 20172019 | |
Notes to Consolidated Financial Statements | |
Report of Independent Registered Public Accounting FirmREPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Board of Directors and StockholdersShareholders
Callon Petroleum Company
Opinion on the financial statements
We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 20192021 and 2018,2020, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019,2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20192021 and 2018,2020, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019,2021, in conformity with accounting principles generally accepted in the United States of America.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 202024, 2022 expressed an unqualified opinion.
Change in accounting principle
As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases in the year ended December 31, 2019 due to the adoption of FASB Accounting Standards Codification Topic 842, Leases.
Basis for opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supportingregarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Mattersaudit matters
TheThe critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
DepletionThe development of estimated proved reserves used in the calculation of depletion, depreciation and amortization expense and evaluation for impairment under the full cost method of oil and gas properties impacted by the Company’s estimation of proved reservesaccounting
As described further in Note 2 to the financial statements, the Company accounts for its oil and gas properties using the full cost method of accounting which requires management to make estimates of proved reserve volumes and future net revenues to record depletion expense and assess its oil and gas properties for potential impairment. To estimate the volume of proved reserves and future net revenue, management makes significant estimates and assumptions including forecasting the production decline rate of producing properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped properties. In addition, the estimation of proved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of depletion expense and potential impairment assessment. We identified the estimation of proved reserves of oil and gas properties as a critical audit matter.
The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions which require a high degree of subjectivity, necessary to estimate the volumevolumes and future net revenues of the Company’s proved reserves require a high degree of subjectivity and could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.
Our audit procedures related to the estimation of proved reserves included the following, among others.
•We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.
•To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to:to historical pricing differentials, operating costs, estimated capitaldevelopment costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
Compared◦We compared the estimated pricing differentials used in the reserve report to prices realized pricesby the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;differentials
Tested◦We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs;costs
Evaluated◦We evaluated the method used to determine the future capital costs and compared estimated future capital expendituresdevelopment costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells;wells to ascertain its reasonableness
Tested◦We tested the working and net revenue interests used in the reserve report by inspecting land and division order records;records
Evaluated◦We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties;properties, and
Applied◦We applied analytical procedures to production forecasts in the reserve report forecasted production by comparing to historical actual results and to the prior year reserve report.
FairEstimate of the fair value of oil and gas properties acquired impacted byand related proved and unproved reserves associated with the Company’s estimation of proved reservesPrimexx Acquisition
As described further in Note 4 to the financial statements, the Company acquired Carrizo Oilcertain producing oil & Gas, Inc.natural gas assets and undeveloped acreage from Primexx Resource Development, LLC and BPP Acquisition, LLC (collectively, “Primexx,” the “Primexx Acquisition”), which requiresrequired management to make estimates of the fair valuesvalue associated with proved reserve volumes.and unproved reserves and related discounted net cash flows. To estimate the volumevolumes of proved and unproved reserves and futurethe associated discounted net revenue,cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of producingproved and unproved properties and forecasting the timing and volume of production associated with the Company’s development plan for proved undeveloped and unproved properties. In addition, the estimation of proved and unproved reserves is also impacted by management’s judgments and estimates regarding the financial performance of wells associated with proved and unproved reserves to determine if wells are expected with reasonable certainty to be economical under the appropriate pricing assumptions required in the estimation of fair value. Significant inputs to the estimate of proved and unproved reserves include estimates of future production volumes, future operating and development costs, future commodity prices and a weighted average cost of capital rate. The estimates of proved and unproved reserves have been developed by specialists, specifically reservoir engineers (referred to as management’s specialists). We identified the estimation of proved and unproved reserves of oil and gas properties acquired as a critical audit matter.
The principal consideration for our determination that the estimation of proved and unproved reserves is a critical audit matter is that changes in certain inputs and assumptions which require a high degree of subjectivity, necessary to estimate the volume and future net revenuesdiscounted cash flows of the Company’s proved and unproved reserves require a high degree of subjectivity and could have a significant impact on the measurement of fair value. In turn, auditing those inputs and assumptions required subjective and complex auditoraudit judgment.
Our audit procedures related to the estimation of proved and unproved reserves included the following, among others.
•We tested the design and operating effectiveness of controls relating to management’s estimation of proved and unproved reserves acquired for the purpose of estimating the fair value assigned to proved properties.value.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved and unproved reserve volumes, and read the reserve report prepared by those specialists.
•We evaluated the independence, objectivity, and professional qualifications of the Company’s external valuation specialists, made inquiries of those valuation specialists regarding the process followed and judgmentsjudgements made to determine the fair value associated with proved and unproved reserve volumes, utilized our valuation specialists to assist in evaluating the appropriateness of the inputs and methodology used in the cash flow model (including future commodity prices and weighted average cost of capital), and read the valuation report prepared by the external specialists.
•To the extent key sensitive inputs and assumptions used to determine proved and unproved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records or other third partyseller provided information, including, but not limited to:to historical pricing differentials, operating costs, estimated capitaldevelopment costs, and ownership
interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:
Compared◦We compared the estimated pricing differentials used in the reserve report to historical prices realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;by Primexx
Tested◦We tested models used to estimate the future operating costs in the acquisition reserve report and compared amounts to historical operating costs;costs
Evaluated◦We evaluated the method used to determine the future capital costs and compared estimated future capital expendituresdevelopment costs used in the valuation reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells;wells
Evaluated◦We tested the working and net revenue interests used in the reserve report by inspecting land and division order records;records
Evaluated◦We evaluated the risk adjustments applied to proved and unproved reserve volumes by comparing against industry accepted factors;factors
Evaluated◦We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped and unproved properties; and
Applied◦We applied analytical procedures to production forecasts in the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report.
/s/ GRANT THORNTON LLP
We have served as the Company’s auditor since 2016.
Houston, Texas
February 28, 202024, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Report of Independent Registered Public Accounting Firm
Board of Directors and StockholdersShareholders
Callon Petroleum Company
Opinion on internal control over financial reporting
We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019,2021, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019,2021, and our report dated February 28, 2020 24, 2022expressed an unqualified opinion on those 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 report on internal control over financial reporting (“Management’s Report”).report. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Carrizo Oil & Gas, Inc., a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 43 and 4 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2019. As indicated in Management’s Report, Carrizo Oil & Gas, Inc. was acquired during 2019. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Carrizo Oil & Gas, Inc.
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/ GRANT THORNTON LLP
Houston, Texas
February 28, 202024, 2022
Callon Petroleum Company
Consolidated Balance Sheets
(In thousands, except par and share data)amounts) | | | | | | | | | | | |
| December 31, |
| 2021 | | 2020 |
ASSETS | | | |
Current assets: | | | |
Cash and cash equivalents | $9,882 | | | $20,236 | |
Accounts receivable, net | 232,436 | | | 133,109 | |
Fair value of derivatives | 22,381 | | | 921 | |
Other current assets | 30,745 | | | 24,103 | |
Total current assets | 295,444 | | | 178,369 | |
Oil and natural gas properties, full cost accounting method: | | | |
Evaluated properties, net | 3,352,821 | | | 2,355,710 | |
Unevaluated properties | 1,812,827 | | | 1,733,250 | |
Total oil and natural gas properties, net | 5,165,648 | | | 4,088,960 | |
| | | |
Other property and equipment, net | 28,128 | | | 31,640 | |
| | | |
Deferred financing costs | 18,125 | | | 23,643 | |
| | | |
Other assets, net | 40,158 | | | 40,256 | |
Total assets | $5,547,503 | | | $4,362,868 | |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current liabilities: | | | |
Accounts payable and accrued liabilities | $569,991 | | | $341,519 | |
| | | |
| | | |
| | | |
| | | |
Fair value of derivatives | 185,977 | | | 97,060 | |
Other current liabilities | 116,523 | | | 58,529 | |
Total current liabilities | 872,491 | | | 497,108 | |
Long-term debt | 2,694,115 | | | 2,969,264 | |
| | | |
Asset retirement obligations | 54,458 | | | 57,209 | |
| | | |
| | | |
Fair value of derivatives | 11,409 | | | 88,046 | |
Other long-term liabilities | 49,262 | | | 40,239 | |
Total liabilities | 3,681,735 | | | 3,651,866 | |
Commitments and contingencies | 0 | | 0 |
Stockholders’ equity: | | | |
Common stock, $0.01 par value, 78,750,000 and 52,500,000 shares authorized; 61,370,684 and 39,758,817 shares outstanding, respectively | 614 | | | 398 | |
Capital in excess of par value | 4,012,358 | | | 3,222,959 | |
Accumulated deficit | (2,147,204) | | | (2,512,355) | |
Total stockholders’ equity | 1,865,768 | | | 711,002 | |
Total liabilities and stockholders’ equity | $5,547,503 | | | $4,362,868 | |
|
| | | | | |
| December 31, |
| 2019 | | 2018 |
ASSETS | | | |
Current assets: | | | |
Cash and cash equivalents | $13,341 | | $16,051 |
Accounts receivable, net | 209,463 |
| | 131,720 |
|
Fair value of derivatives | 26,056 |
| | 65,114 |
|
Other current assets | 19,814 |
| | 9,740 |
|
Total current assets | 268,674 |
| | 222,625 |
|
Oil and natural gas properties, full cost accounting method: | | | |
Evaluated properties, net | 4,682,994 |
| | 2,314,345 |
|
Unevaluated properties | 1,986,124 |
| | 1,404,513 |
|
Total oil and natural gas properties, net | 6,669,118 |
| | 3,718,858 |
|
Operating lease right-of-use assets | 63,908 |
| | — |
|
Other property and equipment, net | 35,253 |
| | 21,901 |
|
Deferred tax asset | 115,720 |
| | — |
|
Deferred financing costs | 22,233 |
| | 6,087 |
|
Fair value of derivatives | 9,216 |
| | — |
|
Other assets, net | 10,716 |
| | 9,702 |
|
Total assets | $7,194,838 | | $3,979,173 |
LIABILITIES AND STOCKHOLDERS’ EQUITY | | | |
Current liabilities: |
| |
|
Accounts payable and accrued liabilities | $511,622 | | $285,849 |
Operating lease liabilities | 42,858 |
| | — |
|
Fair value of derivatives | 71,197 |
| | 10,480 |
|
Other current liabilities | 26,570 |
| | 18,587 |
|
Total current liabilities | 652,247 |
| | 314,916 |
|
Long-term debt | 3,186,109 |
| | 1,189,473 |
|
Operating lease liabilities | 37,088 |
| | — |
|
Asset retirement obligations | 48,860 |
| | 10,405 |
|
Deferred tax liability | — |
| | 9,564 |
|
Fair value of derivatives | 32,695 |
| | 7,440 |
|
Other long-term liabilities | 14,531 |
| | 2,167 |
|
Total liabilities | 3,971,530 |
| | 1,533,965 |
|
Commitments and contingencies |
| |
|
Stockholders’ equity: |
| |
|
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, respectively | — |
| | 15 |
|
Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, respective; 396,600,022 and 227,582,575 shares outstanding, respectively | 3,966 |
| | 2,276 |
|
Capital in excess of par | 3,198,076 |
| | 2,477,278 |
|
Retained earnings (Accumulated deficit) | 21,266 |
| | (34,361 | ) |
Total stockholders’ equity | 3,223,308 |
| | 2,445,208 |
|
Total liabilities and stockholders’ equity | $7,194,838 | | $3,979,173 |
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(In thousands, except per share data)amounts) | | | | | | | | | | | | | | | | | |
| For the Year Ended December 31, |
| 2021 | | 2020 | | 2019 |
Operating Revenues: | | | | | |
Oil | $1,516,225 | | | $850,667 | | | $633,107 | |
Natural gas | 141,493 | | | 51,866 | | | 36,390 | |
Natural gas liquids | 193,861 | | | 81,295 | | | 2,075 | |
Sales of purchased oil and gas | 193,451 | | | 49,319 | | | — | |
Total operating revenues | 2,045,030 | | | 1,033,147 | | | 671,572 | |
| | | | | |
Operating Expenses: | | | | | |
Lease operating | 203,141 | | | 194,101 | | | 91,827 | |
Production and ad valorem taxes | 100,160 | | | 62,638 | | | 42,651 | |
Gathering, transportation and processing | 80,970 | | | 77,309 | | | — | |
Cost of purchased oil and gas | 201,088 | | | 51,766 | | | — | |
Depreciation, depletion and amortization | 356,556 | | | 480,631 | | | 240,642 | |
General and administrative | 50,483 | | | 37,187 | | | 45,331 | |
Impairment of evaluated oil and gas properties | — | | | 2,547,241 | | | — | |
Merger, integration and transaction | 14,289 | | | 28,482 | | | 74,363 | |
Other operating | 3,366 | | | 10,644 | | | 4,100 | |
Total operating expenses | 1,010,053 | | | 3,489,999 | | | 498,914 | |
Income (Loss) From Operations | 1,034,977 | | | (2,456,852) | | | 172,658 | |
| | | | | |
Other (Income) Expenses: | | | | | |
Interest expense, net of capitalized amounts | 102,012 | | | 94,329 | | | 2,907 | |
Loss on derivative contracts | 522,300 | | | 27,773 | | | 62,109 | |
(Gain) loss on extinguishment of debt | 41,040 | | | (170,370) | | | 4,881 | |
Other (income) expense | 4,294 | | | 2,983 | | | (468) | |
Total other (income) expense | 669,646 | | | (45,285) | | | 69,429 | |
| | | | | |
Income (Loss) Before Income Taxes | 365,331 | | | (2,411,567) | | | 103,229 | |
Income tax expense | (180) | | | (122,054) | | | (35,301) | |
Net Income (Loss) | $365,151 | | | ($2,533,621) | | | $67,928 | |
Preferred stock dividends | — | | | — | | | (3,997) | |
Loss on redemption of preferred stock | — | | | — | | | (8,304) | |
Income (Loss) Available to Common Stockholders | $365,151 | | | ($2,533,621) | | | $55,627 | |
| | | | | |
Income (Loss) Available to Common Stockholders Per Common Share: | | | | | |
Basic | $7.51 | | | ($63.79) | | | $2.39 | |
Diluted | $7.26 | | | ($63.79) | | | $2.38 | |
| | | | | |
Weighted Average Common Shares Outstanding: | | | | | |
Basic | 48,612 | | | 39,718 | | | 23,313 | |
Diluted | 50,311 | | | 39,718 | | | 23,340 | |
|
| | | | | | | | | | | |
| For the Year Ended December 31, |
| 2019 | | 2018 | | 2017 |
Operating Revenues: | | | | | |
Oil |
| $633,107 |
| |
| $530,898 |
| |
| $322,374 |
|
Natural gas | 36,390 |
| | 56,726 |
| | 44,100 |
|
Natural gas liquids | 2,075 |
| | — |
| | — |
|
Total operating revenues | 671,572 |
| | 587,624 |
| | 366,474 |
|
| | | | | |
Operating Expenses: | | | | | |
Lease operating | 91,827 |
| | 69,180 |
| | 49,907 |
|
Production taxes | 42,651 |
| | 35,755 |
| | 22,396 |
|
Depreciation, depletion and amortization | 240,642 |
| | 182,783 |
| | 116,391 |
|
General and administrative | 45,331 |
| | 35,293 |
| | 27,067 |
|
Merger and integration expenses | 74,363 |
| | — |
| | — |
|
Settled share-based awards | 3,024 |
| | — |
| | 6,351 |
|
Other operating expense | 1,076 |
| | 5,083 |
| | 2,916 |
|
Total operating expenses | 498,914 |
| | 328,094 |
| | 225,028 |
|
Income From Operations | 172,658 |
| | 259,530 |
| | 141,446 |
|
| | | | | |
Other (Income) Expenses: | | | | | |
Interest expense, net of capitalized amounts | 2,907 |
| | 2,500 |
| | 2,159 |
|
(Gain) loss on derivative contracts | 62,109 |
| | (48,544 | ) | | 18,901 |
|
Loss on extinguishment of debt | 4,881 |
| | — |
| | — |
|
Other income | (468 | ) | | (2,896 | ) | | (1,311 | ) |
Total other (income) expense | 69,429 |
| | (48,940 | ) | | 19,749 |
|
| | | | | |
Income Before Income Taxes | 103,229 |
| | 308,470 |
| | 121,697 |
|
Income tax expense | 35,301 |
| | 8,110 |
| | 1,273 |
|
Net Income |
| $67,928 |
| |
| $300,360 |
| |
| $120,424 |
|
Preferred stock dividends | (3,997 | ) | | (7,295 | ) | | (7,295 | ) |
Loss on redemption of preferred stock | (8,304 | ) | | — |
| | — |
|
Income Available to Common Stockholders |
| $55,627 |
| |
| $293,065 |
| |
| $113,129 |
|
| | | | | |
Income Available to Common Stockholders Per Common Share: | | | | | |
Basic |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
|
Diluted |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
|
| | | | | |
Weighted Average Common Shares Outstanding: | | | | | |
Basic | 233,140 |
| | 216,941 |
| | 201,526 |
|
Diluted | 233,550 |
| | 217,596 |
| | 202,102 |
|
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(In thousands, except share amounts)thousands)
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Retained | | |
| Preferred | | Common | | Capital in | | Earnings | | Total |
| Stock | | Stock | | Excess | | (Accumulated | | Stockholders’ |
| Shares | | $ | | Shares | | $ | | of Par | | Deficit) | | Equity |
Balance at 12/31/2018 | 1,459 | | | $15 | | | 22,757 | | | $2,276 | | | $2,477,278 | | | ($34,361) | | | $2,445,208 | |
Net income | — | | | — | | | — | | | — | | | — | | | 67,928 | | | 67,928 | |
Shares issued pursuant to employee benefit plans | — | | | — | | | 2 | | | — | | | 154 | | | — | | | 154 | |
Restricted stock | — | | | — | | | 79 | | | 8 | | | 11,622 | | | — | | | 11,630 | |
Common stock issued for Carrizo Acquisition | — | | | — | | | 16,821 | | | 1,682 | | | 763,691 | | | — | | | 765,373 | |
Common stock warrants reissued in conjunction with Carrizo Acquisition | — | | | — | | | — | | | — | | | 10,029 | | | — | | | 10,029 | |
Preferred stock dividend | — | | | — | | | — | | | — | | | — | | | (3,997) | | | (3,997) | |
Preferred stock redemption | (1,459) | | | (15) | | | — | | | — | | | (64,698) | | | — | | | (64,713) | |
Loss on redemption of preferred stock | — | | | — | | | — | | | — | | | — | | | (8,304) | | | (8,304) | |
Balance at 12/31/2019 | — | | | $— | | | 39,659 | | | $3,966 | | | $3,198,076 | | | $21,266 | | | $3,223,308 | |
Net loss | — | | | — | | | — | | | — | | | — | | | (2,533,621) | | | (2,533,621) | |
Restricted stock | — | | | — | | | 100 | | | 10 | | | 12,213 | | | — | | | 12,223 | |
Reverse stock split | — | | | — | | | — | | | (3,578) | | | 3,578 | | | — | | | — | |
Issuance of common stock warrants | — | | | — | | | — | | | — | | | 9,109 | | | — | | | 9,109 | |
Other | — | | | — | | | — | | | — | | | (17) | | | — | | | (17) | |
Balance at 12/31/2020 | — | | | $— | | | 39,759 | | | $398 | | | $3,222,959 | | | ($2,512,355) | | | $711,002 | |
Net income | — | | | — | | | — | | | — | | | — | | | 365,151 | | | 365,151 | |
Restricted stock | — | | | — | | | 156 | | | 2 | | | 10,949 | | | — | | | 10,951 | |
Warrant exercises | — | | | — | | | 6,913 | | | 69 | | | 134,748 | | | — | | | 134,817 | |
Common stock issued for Primexx Acquisition | — | | | — | | | 9,030 | | | 90 | | | 420,610 | | | — | | | 420,700 | |
Common stock issued for Second Lien Notes Exchange | — | | | — | | | 5,513 | | | 55 | | | 223,092 | | | — | | | 223,147 | |
Balance at 12/31/2021 | — | | | $— | | | 61,371 | | | $614 | | | $4,012,358 | | | ($2,147,204) | | | $1,865,768 | |
|
| | | | | | | | | | | | | | | | | | | | | | |
| | | | | | | | | | | Retained | | |
| Preferred | | Common | | Capital in | | Earnings | | Total |
| Stock | | Stock | | Excess | | (Accumulated | | Stockholders' |
| Shares | | $ | | Shares | | $ | | of Par | | Deficit) | | Equity |
Balance at 12/31/2016 | 1,459 |
| | $15 | | 201,041 |
| | $2,010 | | $2,171,514 | |
| ($440,137 | ) | | $1,733,402 |
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 120,424 |
| | 120,424 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 26 |
| | — |
| | 311 |
| | — |
| | 311 |
|
Restricted stock | — |
| | — |
| | 769 |
| | 8 |
| | 9,098 |
| | — |
| | 9,106 |
|
Common stock issued | — |
| | — |
| | — |
| | — |
| | 18 |
| | — |
| | 18 |
|
Impact of forfeiture estimate | — |
| | — |
| | — |
| | — |
| | 418 |
| | (418 | ) | | — |
|
Preferred stock dividend | — |
| | — |
| | — |
| | — |
| | — |
| | (7,295 | ) | | (7,295 | ) |
Balance at 12/31/2017 | 1,459 |
| | $15 | | 201,836 |
| | $2,018 | | $2,181,359 | |
| ($327,426 | ) | | $1,855,966 |
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 300,360 |
| | 300,360 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 45 |
| | — |
| | 533 |
| | — |
| | 533 |
|
Restricted stock | — |
| | — |
| | 402 |
| | 5 |
| | 7,651 |
| | — |
| | 7,656 |
|
Common stock issued | — |
| | — |
| | 25,300 |
| | 253 |
| | 287,735 |
| | — |
| | 287,988 |
|
Preferred stock dividend | — |
| | — |
| | — |
| | — |
| | — |
| | (7,295 | ) | | (7,295 | ) |
Balance at 12/31/2018 | 1,459 |
| | $15 | | 227,583 |
| | $2,276 | | $2,477,278 | |
| ($34,361 | ) | | $2,445,208 |
Net income | — |
| | — |
| | — |
| | — |
| | — |
| | 67,928 |
| | 67,928 |
|
Shares issued pursuant to employee benefit plans | — |
| | — |
| | 24 |
| | — |
| | 154 |
| | — |
| | 154 |
|
Restricted stock | — |
| | — |
| | 779 |
| | 8 |
| | 11,622 |
| | — |
| | 11,630 |
|
Common stock issued for Carrizo Acquisition | — |
| | — |
| | 168,214 |
| | 1,682 |
| | 763,691 |
| | — |
| | 765,373 |
|
Common stock warrants reissued for Carrizo Acquisition | — |
| | — |
| | — |
| | — |
| | 10,029 |
| | — |
| | 10,029 |
|
Preferred stock dividend | — |
| | — |
| | — |
| | — |
| | — |
| | (3,997 | ) | | (3,997 | ) |
Preferred stock redemption | (1,459 | ) | | (15 | ) | | — |
| | — |
| | (64,698 | ) | | — |
| | (64,713 | ) |
Loss on redemption of preferred stock | — |
| | — |
| | — |
| | — |
| | — |
| | (8,304 | ) | | (8,304 | ) |
Balance at 12/31/2019 | — |
| |
| $— |
| | 396,600 |
| | $3,966 | | $3,198,076 | | $21,266 | | $3,223,308 |
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(In thousands) | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Cash flows from operating activities: | | | | | |
Net income (loss) | $365,151 | | | ($2,533,621) | | | $67,928 | |
Adjustments to reconcile net income (loss) to net cash provided by operating activities: | | | | | |
Depreciation, depletion and amortization | 356,556 | | | 480,631 | | | 245,936 | |
Impairment of evaluated oil and gas properties | — | | | 2,547,241 | | | — | |
Amortization of non-cash debt related items, net | 10,124 | | | 3,901 | | | 2,907 | |
Deferred income tax expense | — | | | 118,607 | | | 35,301 | |
Loss on derivative contracts | 522,300 | | | 27,773 | | | 62,109 | |
Cash received (paid) for commodity derivative settlements, net | (395,097) | | | 98,870 | | | (3,789) | |
| | | | | |
(Gain) loss on extinguishment of debt | 41,040 | | | (170,370) | | | 4,881 | |
Non-cash expense related to share-based awards | 12,923 | | | 2,663 | | | 11,391 | |
| | | | | |
| | | | | |
| | | | | |
Other, net | 11,037 | | | 7,087 | | | (1,515) | |
Changes in current assets and liabilities: | | | | | |
Accounts receivable | (86,402) | | | 75,770 | | | (35,071) | |
Other current assets | (10,399) | | | (6,550) | | | (4,166) | |
Accounts payable and accrued liabilities | 146,910 | | | (92,227) | | | 82,290 | |
| | | | | |
| | | | | |
Other, net | — | | | — | | | 8,114 | |
Net cash provided by operating activities | 974,143 | | | 559,775 | | | 476,316 | |
Cash flows from investing activities: | | | | | |
Capital expenditures | (578,487) | | | (664,231) | | | (640,540) | |
Acquisition of oil and gas properties | (493,732) | | | (12,923) | | | (42,266) | |
Proceeds from sales of assets | 188,101 | | | 178,970 | | | 294,417 | |
Cash paid for settlements of contingent consideration arrangements, net | — | | | (40,000) | | | — | |
Other, net | 7,718 | | | 8,301 | | | — | |
Net cash used in investing activities | (876,400) | | | (529,883) | | | (388,389) | |
Cash flows from financing activities: | | | | | |
Borrowings on Credit Facility | 2,140,500 | | | 5,353,000 | | | 2,455,900 | |
Payments on Credit Facility | (2,340,500) | | | (5,653,000) | | | (895,500) | |
Issuance of 8.00% Senior Notes due 2028 | 650,000 | | | — | | | — | |
Redemption of 6.25% Senior Notes | (542,755) | | | — | | | — | |
Issuance of 9.00% Second Lien Senior Secured Notes due 2025 | — | | | 300,000 | | | — | |
Discount on the issuance of 9.00% Second Lien Senior Secured Notes due 2025 | — | | | (35,270) | | | — | |
Issuance of September 2020 Warrants | — | | | 23,909 | | | — | |
Payment to terminate Prior Credit Facility | — | | | — | | | (475,400) | |
Repayment of Carrizo’s senior secured revolving credit facility | — | | | — | | | (853,549) | |
Repayment of Carrizo’s preferred stock | — | | | — | | | (220,399) | |
| | | | | |
Payment of preferred stock dividends | — | | | — | | | (3,997) | |
Payment of deferred financing and debt exchange costs | (12,672) | | | (10,811) | | | (22,480) | |
Tax withholdings related to restricted stock units | (2,280) | | | (509) | | | (2,195) | |
Redemption of preferred stock | — | | | — | | | (73,017) | |
Other, net | (390) | | | (316) | | | — | |
Net cash used in financing activities | (108,097) | | | (22,997) | | | (90,637) | |
Net change in cash and cash equivalents | (10,354) | | | 6,895 | | | (2,710) | |
Balance, beginning of period | 20,236 | | | 13,341 | | | 16,051 | |
Balance, end of period | $9,882 | | | $20,236 | | | $13,341 | |
|
| | | | | | | | |
| Years Ended December 31, |
| 2019 | | 2018 | | 2017 |
Cash flows from operating activities: | | | | | |
Net income | $67,928 | | $300,360 | | $120,424 |
Adjustments to reconcile net income to net cash provided by operating activities: | | | | | |
Depreciation, depletion and amortization | 245,936 |
| | 185,605 |
| | 118,728 |
|
Amortization of non-cash debt related items | 2,907 |
| | 2,483 |
| | 2,150 |
|
Deferred income tax expense | 35,301 |
| | 8,110 |
| | 1,273 |
|
(Gain) loss on derivative contracts | 62,109 |
| | (48,544 | ) | | 18,901 |
|
Cash paid for commodity derivative settlements, net | (3,789 | ) | | (27,272 | ) | | (8,472 | ) |
(Gain) loss on sale of other property and equipment | (90 | ) | | (144 | ) | | 62 |
|
Non-cash loss on early extinguishment of debt | 4,881 |
| | — |
| | — |
|
Non-cash expense related to equity share-based awards | 9,767 |
| | 6,289 |
| | 8,254 |
|
Change in the fair value of liability share-based awards | 1,624 |
| | 375 |
| | 3,288 |
|
Payments to settle asset retirement obligations | (4,148 | ) | | (1,469 | ) | | (2,047 | ) |
Payments for cash-settled restricted stock unit awards | (1,425 | ) | | (4,990 | ) | | (13,173 | ) |
Changes in current assets and liabilities: | | | | | |
Accounts receivable | (35,071 | ) | | (17,351 | ) | | (44,495 | ) |
Other current assets | (4,166 | ) | | (7,601 | ) | | 108 |
|
Current liabilities | 86,438 |
| | 74,311 |
| | 30,947 |
|
Other | 8,114 |
| | (2,508 | ) | | (6,057 | ) |
Net cash provided by operating activities | 476,316 |
| | 467,654 |
| | 229,891 |
|
Cash flows from investing activities: | | | | | |
Capital expenditures | (640,540 | ) | | (611,173 | ) | | (419,839 | ) |
Acquisitions | (42,266 | ) | | (718,793 | ) | | (718,456 | ) |
Acquisition deposit | — |
| | — |
| | 45,238 |
|
Proceeds from sales of assets | 294,417 |
| | 9,009 |
| | 20,525 |
|
Additions to other assets | — |
| | (3,100 | ) | | — |
|
Net cash used in investing activities | (388,389 | ) | | (1,324,057 | ) | | (1,072,532 | ) |
Cash flows from financing activities: | | | | | |
Borrowings on senior secured revolving credit facility | 2,455,900 |
| | 500,000 |
| | 25,000 |
|
Payments on senior secured revolving credit facility | (895,500 | ) | | (325,000 | ) | | — |
|
Payment to terminate Prior Credit Facility | (475,400 | ) | | — |
| | — |
|
Repayment of Carrizo’s senior secured revolving credit facility | (853,549 | ) | | — |
| | — |
|
Repayment of Carrizo’s preferred stock | (220,399 | ) | | — |
| | — |
|
Issuance of 6.125% Senior Notes due 2024 | — |
| | — |
| | 200,000 |
|
Premium on the issuance of 6.125% Senior Notes due 2024 | — |
| | — |
| | 8,250 |
|
Issuance of 6.375% Senior Notes due 2026 | — |
| | 400,000 |
| | — |
|
Issuance of common stock | — |
| | 287,988 |
| | — |
|
Payment of preferred stock dividends | (3,997 | ) | | (7,295 | ) | | (7,295 | ) |
Payment of deferred financing costs | (22,480 | ) | | (9,430 | ) | | (7,194 | ) |
Tax withholdings related to restricted stock units | (2,195 | ) | | (1,804 | ) | | (1,118 | ) |
Redemption of preferred stock | (73,017 | ) | | — |
| | — |
|
Net cash provided by (used in) financing activities | (90,637 | ) | | 844,459 |
| | 217,643 |
|
Net change in cash and cash equivalents | (2,710 | ) | | (11,944 | ) | | (624,998 | ) |
Balance, beginning of period | 16,051 |
| | 27,995 |
| | 652,993 |
|
Balance, end of period | $13,341 | | $16,051 | | $27,995 |
The accompanying notes are an integral part of these consolidated financial statements.
INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS | | | | | | | | | | | |
1. | | 10. | |
2. | | 11. | |
3. | | 12. | |
4. | | 13. | |
5. | | 14. | |
6. | | 15. | |
7. | | 16. | |
8. | | 17. | |
9. | | 18. | |
|
| | | |
1. | | 11. | Stockholders’ Equity |
2. | | 12. | |
3. | Revenue Recognition | 13. | |
4. | | 14. | |
5. | Property and Equipment, Net | 15. | |
6. | | 16. | Accounts Payable and Accrued Liabilities |
7. | | 17. | Commitments and Contingencies |
8. | | 18. | Subsequent Events (Unaudited) |
9. | | 19. | |
10. | | 20. | |
Note 1 – Description of Business
Callon Petroleum Company is an independent oil and natural gas company establishedfocused on the acquisition, exploration and development of high-quality assets in 1950. The Company was incorporated under the lawsleading oil plays of the state of Delaware in 1994South and succeeded to the business of a publicly traded limited partnership, a joint venture with a consortium of European investors and an independent energy company.West Texas. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.
Callon is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. In 2019, through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company doubled its core acreage position in the Delaware Basin and enteredTexas, as well as the Eagle Ford Shale.in South Texas. The Company’s primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generatingflow-generating business in the Eagle Ford Shale.Ford.
Note 2 – Summary of Significant Accounting Policies
Basis of Presentation and Principles of Consolidation
The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”).GAAP. The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation. Such reclassifications did not have a material impact on prior period financial statements. The Company evaluates events subsequent to the balance sheet date through the date the financial statements are issued.
Use of Estimates
The preparation of financial statements in conformity with U.S. GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of provedevaluated oil and gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, fair value of second lien notes upon issuance, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Cash and Cash Equivalents
The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.
Accounts Receivable, Net
Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for doubtful accountscredit losses and bad debt expense was immaterial for all periodperiods presented.
Concentration of Credit Risk and Major Customers
The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented:
|
| | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
Rio Energy International, Inc. | | 26% | | 28% | | 17% |
Enterprise Crude Oil, LLC | | 19% | | 14% | | 18% |
Plains Marketing, L.P. | | 15% | | 21% | | 29% |
Shell Trading Company | | 10% | | * | | * |
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
Shell Trading Company | | 20% | | 31% | | 10% |
Trafigura Trading, LLC | | 15 | | * | | * |
Occidental Energy Marketing, Inc. | | 13 | | * | | * |
Valero Marketing and Supply Company | | 13 | | 23 | | * |
Rio Energy International, Inc. | | * | | * | | 26 |
Enterprise Crude Oil, LLC | | * | | * | | 19 |
Plains Marketing, L.P. | | * | | * | | 15 |
* - Less than 10% for the applicable year.
TheSee “Note 8 - Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.
Oil and Natural Gas Properties
The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred.
Proceeds from the sale or dispositiondivestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 20182021, 2020 and 2017,2019, the Company did not have any sales of oil and gas properties that significantly altered such relationship.
From time to time, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and the difference is accounted for as an adjustment of capitalized costs with no gain or loss recognized pursuant to the rules governing full cost accounting, unless such adjustment would significantly alter the relationship between capitalized costs and proved reserves of oil, NGL and natural gas.
Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such amortizationdepletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.
Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed onwhen the proved reserves have been assigned to the properties or the Company determines that these costs have been impaired. The Company assesses properties on an individual basis or as a group and considers the following factors, among others, to determine if these costs have been impaired: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. Geological and geophysical costs not associated with specific prospects are recorded to evaluated oil and gas property costs as incurred. The amount of interest costs capitalized is determined on a quarterly basis based on the average balance of unprovedunevaluated properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.
Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from estimated proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas
properties, less related deferred income taxes, over the cost center ceiling is recognized as a write-downan impairment of evaluated oil and gas properties. A write-downAn impairment recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.
The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales12-Month Average Realized Price of oil, NGLs, and natural gas, on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did 0tnot recognize a write-downimpairments of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018,2021 and 2017.2019. Primarily as a result of a 31% decrease in the 12-Month Average Realized Price of oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year ended December 31, 2020.
Other Property and Equipment
The Company depreciates itsDepreciation of other property and equipment is recognized using the straight-line method based on estimated useful lives of threeranging from two to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.
Deferred Financing Costs
Deferred financing costs associated with the Company’s senior notesSecond Lien Notes and the Unsecured Senior Notes, both defined below, are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-lineeffective interest method over the terms of the related senior notes.debt. Deferred financing costs associated with the revolving credit facilityCredit Facility, as defined below, are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Amortization of deferred financing costs, net of amortization of premiums, of $2.9 million, $2.5 million and $2.2 million were recorded for the years ended December 31, 2019, 2018 and 2017, respectively.
Asset Retirement Obligations
The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated oil and gas properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information.
Derivative Instruments
The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. The Company does not enter into commodity derivative instruments for speculative or trading purposes. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into
Settlements of the Company’s commodity derivative instruments are based on the difference between the contract price or prices specified in the derivative instrument and a benchmark price, such as the NYMEX price. To determine the fair value of the Company’s derivative instruments, the Company utilizes present value methods that include assumptions about commodity prices based on those observed in underlying markets. See “Note 9 - Fair Value Measurements” for speculative purposes.additional information regarding fair value.
The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.
The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which
the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion.
Revenue Recognition
The Company recognizes revenues from the sales of oil, and natural gas, and NGLs to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation, therefore, future volumes are recorded monthlywholly unsatisfied and are based on estimateddisclosure of the transaction price allocated to remaining performance obligations is not required.
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to athe purchaser and the expected price tothat will be received. Variancesreceived for the sale of the product. The Company records the differences between estimates and the actual amounts received are recordedfor product sales in the month that payment is received.received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant. See “Note 3 - Revenue Recognition” for further discussion.
Income Taxes
Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. U.S. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. As of December 31, 2019 and 2018, the Company did 0t have a valuation allowance against its deferred tax assets. See “Note 12 - Income Taxes” for further discussion.
Share-Based Compensation
The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below.
RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years).
Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs previously granted by Carrizo that were outstandingSARs”) are remeasured at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period.period with the change in fair value recorded as share-based compensation expense. The liability for Cash SARs is classified as “Other current liabilities” in the consolidated balance sheets as all outstanding awards are vested. The Cash SARs outstanding will expire between one year and sevenfive years, depending on the date of grant.
Supplemental Cash Flow Information
The following table sets forth supplemental cash flow information for the periods indicated:
|
| | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 | | 2017 |
| | (In thousands) |
Interest paid, net of capitalized amounts | |
| $— |
| |
| $— |
| |
| $— |
|
Income taxes paid (1) | | — |
| | — |
| | — |
|
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | |
Operating cash flows from operating leases | |
| $3,414 |
| |
| $— |
| |
| $— |
|
Investing cash flows from operating leases | | 32,529 |
| | — |
| | — |
|
Non-cash investing and financing activities: | | | | | | |
Change in accrued capital expenditures | |
| ($31,475 | ) | |
| ($52,757 | ) | |
| ($39,532 | ) |
Change in asset retirement costs | | 13,559 |
| | 8,730 |
| | (607 | ) |
Contingent consideration arrangement | | 8,512 |
| | — |
| | — |
|
ROU assets obtained in exchange for lease liabilities: | | | | | | |
Operating leases | |
| $66,914 |
| |
| $— |
| |
| $— |
|
Financing leases | | 2,197 |
| | — |
| | — |
|
| | | | | | | | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 | | 2019 |
| | (In thousands) |
Interest paid, net of capitalized amounts | | $85,042 | | | $91,269 | | | $— | |
Income taxes paid (1) | | — | | | — | | | — | |
Cash paid for amounts included in the measurement of lease liabilities: | | | | | | |
Operating cash flows from operating leases | | $26,681 | | | $44,314 | | | $3,414 | |
Investing cash flows from operating leases | | 18,598 | | | 24,234 | | | 32,529 | |
Non-cash investing and financing activities: | | | | | | |
Change in accrued capital expenditures | | $63,444 | | | ($64,465) | | | ($31,475) | |
Change in asset retirement costs | | 2,905 | | | 8,605 | | | 13,559 | |
Contingent consideration arrangement | | — | | | — | | | 8,512 | |
ROU assets obtained in exchange for lease liabilities: | | | | | | |
Operating leases | | $24,301 | | | $8,070 | | | $66,914 | |
Financing leases | | — | | | — | | | 2,197 | |
| |
(1) | The Company did 0t pay any federal income tax for any of the years in the three year period ending December 31, 2019. |
(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2021.
Earnings per Share
The Company’s basic net income (loss) attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income (loss) attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. When a loss attributable to common shareholders per common share exists, all potentially dilutive common shares outstanding are anti-dilutive and therefore excluded from the calculation of diluted weighted average shares outstanding. See “Note 6 - Earnings Per Share” for further discussion.
Industry Segment and Geographic Information
The Company operates in 1 industry segment, which is the exploration, development, and production of crude oil, NGLs,natural gas, and natural gas.NGLs. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.
Recently Adopted Accounting Standards
Leases.Income Taxes. In FebruaryDecember 2019, the FASB released ASU No. 2019-12 (“ASU 2019-12”), Income Taxes (Topic 740) – Simplifying the Accounting for Income Taxes, which removes certain exceptions for recognizing deferred taxes for investments, performing intraperiod allocation and calculating income taxes in interim periods. The ASU also adds guidance to reduce complexity in certain areas, including recognizing deferred taxes for tax goodwill and allocating taxes to members of a consolidated group. The amended standard is effective for fiscal years beginning after December 15, 2020, with early adoption permitted. The Company adopted ASU 2019-12 on January 1, 2021. The adoption of ASU 2019-12 did not have a material impact to the Company’s consolidated financial statements or disclosures.
Credit Losses. In June 2016, the FASB issued ASU No. 2016-02, Leases2016-13, Financial Instruments-Credit Losses (Topic 842)326): AmendmentsMeasurement of Credit Losses on Financial Instruments, followed by other related ASUs that provided targeted improvements (collectively “ASU 2016-13”). ASU 2016-13 provides financial statement users with more decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity at each reporting date. The guidance is to be applied using a modified retrospective method and is effective for fiscal years beginning after December 15, 2019, with early adoption permitted. The Company adopted ASU 2016-13 on January 1, 2020. The adoption of ASU 2016-13 did not have a material impact to the FASBCompany’s consolidated financial statements or disclosures.
Recently Issued Accounting Standards Codification.
In January 2018,March 2020, the FASB issued ASU No. 2018-01, Leases2020-04, Reference Rate Reform (Topic 842)848): Land Easement Practical ExpedientFacilitation of the Effects of Reference Rate Reform on Financial Reporting (“ASU 2020-04”) followed by ASU No. 2021-01, Reference Rate Reform (Topic 848): Scope (“ASU 2021-01”), issued in January 2021 to provide clarifying guidance regarding the scope of Topic 848. ASU 2020-04 was issued to provide optional guidance for Transitiona limited period of time to Topic 842. ease the potential burden in accounting for (or recognizing the effects of)
reference rate reform on financial reporting. Generally, the guidance is to be applied as of any date from the beginning of an interim period that includes or is subsequent to March 12, 2020, or prospectively from a date within an interim period that includes or is subsequent to March 12, 2020, up to the date that the financial statements are available to be issued. ASU 2020-04 and ASU 2021-01 are effective for all entities through December 31, 2022. As of December 31, 2021, the Company has not elected to use the optional guidance and continues to evaluate the options provided by ASU 2020-04 and ASU 2021-01. Please refer to “Note 7 – Borrowings” for discussion of the use of the adjusted LIBO rate in connection with borrowings under the Credit Facility.
In July 2018,August 2020, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019,2020-06, Debt - Debt with Conversion and Other Options (Subtopic 470-20) and Derivatives and Hedging - Contracts in Entity’s Own Equity (Subtopic 815-40) (“ASU 2020-06”). ASU 2020-06 was issued to reduce the FASB issuedcomplexity associated with accounting for certain financial instruments with characteristics of liabilities and equity. The guidance is to be applied using either a modified retrospective or a fully retrospective method. ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”).
Effective2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company will adopt ASU 2020-06 effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained.2022. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.
Upon adoption, the Company implemented policy elections and practical expedients which include the following:
package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance
excluding ROU assets and lease liabilities for leases with terms that are less than one year;
combining lease and non-lease components and accounting for them as a single lease (elected by asset class);
excluding land easements that existed or expired prior to adoption; and
policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.
Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 didASU 2020-06 is not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion.
Recently Issued ASUs
None that are expected to have a material impact on ourthe Company’s consolidated financial statements.statements or disclosures.
Note 3 – Revenue Recognition
Revenue from contracts with customers
Oil sales
Under the Company’s oil sales contracts it sells oil production at the point of delivery and collects an agreed upon index price, net of pricing differentials. The Company recognizes revenue when control transfers to the purchaser at the point of delivery at the net price received. The Company has certain oil sales that occur at market locations downstream of the production area. Given the structure of these arrangements and where control transfers, the Company separately recognizes fees and other deductions incurred prior to control transfer as “Gathering, transportation and processing” in its consolidated statements of operations.
Natural gas and NGL sales
Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow the Company to take title to NGLs resulting from the processing of our natural gas. As a result, sales and reserve volumes, prices, and revenues for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for sales and reserve volumes, prices, and revenues specifically associated with Carrizo, sales and reserve volumes, prices, and revenues for NGLs were presented with natural gas.
Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of naturalNGLs and residue gas. The revenue received fromCompany evaluates whether the saleprocessing entity is the principal or the agent in the transaction for each of NGLs associated with certain contracts is included inour natural gas sales. Under these processing agreements and have concluded that the Company maintains control through processing or has the right to take residue gas and/or NGLs in-kind at the tailgate of the midstream entity’s processing plant and subsequently market the product. The Company recognizes revenue when control oftransfers to the purchaser at the delivery point based on the contractual index price received.
The Company recognizes revenue for natural gas changes at the pointand NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of delivery, the treatment of gathering and treating fees are recorded net of revenues. For other contracts that were assumed in the Carrizo Acquisition, defined below, whereoperations as the Company maintains control throughout processing,processing.
Oil and gas purchase and sale arrangements
Sales of purchased oil and gas represent revenues the Company records NGL revenue separately on its consolidated statementreceives from sales of operationscommodities purchased from a third-party. The Company recognizes these revenues and presents the gathering a treating fees as an expense recorded in lease operating expense.
For the majoritypurchase of the Company’s natural gas sales processing contracts, gathering and treating fees have historically been recordedthird-party commodities, as an expensewell as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in lease operating expense inthese transactions by assuming control of the statement of operations. The Company modifiedpurchased commodity before it is transferred to the presentation of revenues and expenses to include these fees net of revenues effective January 1, 2018 upon adopting ASC 606 - Revenuecustomer.
Accounts Receivable from Revenues from Contracts with Customers. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the year ended December 31, 2017, $3.4 million of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations.
Accounts receivable from revenues from contracts with customersCustomers
Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 20192021 and 20182020 of $165.3$171.8 million and $87.1$100.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The increase from December 31, 2018 is primarily due to the Carrizo Acquisition.
Transaction price allocated to remaining performance obligations
For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.
Prior period performance obligations
The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.
Note 4 – Acquisitions and Divestitures
2021 Acquisitions and Divestitures
Primexx Acquisition. On October 1, 2021, the Company closed on the acquisition of certain producing oil and gas properties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC
(“Primexx”) and BPP Acquisition, LLC (“BPP”) for an adjusted purchase price of approximately $444.8 million in cash, inclusive of the deposit paid at signing, 8.84 million shares of the Company’s common stock and approximately $25.2 million paid upon final closing for total consideration of $880.8 million (the “Primexx Acquisition”). The Company funded the cash portion of the total consideration with borrowings under its Credit Facility, as defined below. Of the 8.84 million shares of the Company’s common stock issued upon closing, 2.6 million shares were held in escrow pursuant to the purchase and sale agreements with Primexx and BPP (collectively, the “Primexx PSAs”). Additionally, 50% of the shares held in escrow will be released six months after the closing date, and the remaining shares will be released twelve months after the closing date, in each case subject to holdback for the satisfaction of any applicable indemnification claims that may be made under the Primexx PSAs.
Also, pursuant to the Primexx PSAs, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to the Company for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $33.1 million, net of customary purchase price adjustments, of which $22.4 million closed during the fourth quarter of 2021 and the remaining $10.7 million closed in early January 2022.
The Primexx Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values with information available at that time. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available. The Company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary allocation of the total estimated consideration of $903.2 million to the assets acquired and liabilities assumed as of the acquisition date.
| | | | | | | | |
| | Preliminary Purchase Price Allocation |
| | (In thousands) |
Assets: | | |
Other current assets | | $10,213 | |
Evaluated oil and natural gas properties | | 677,372 | |
Unevaluated properties | | 275,783 | |
Total assets acquired | | $963,368 | |
| | |
Liabilities: | | |
Suspense payable | | $16,447 | |
Other current liabilities | | 32,350 | |
Asset retirement obligation | | 1,898 | |
Other long-term liabilities | | 9,425 | |
Total liabilities assumed | | $60,120 | |
| | |
Total consideration | | $903,248 | |
Approximately $114.3 million of revenues and $32.1 million of direct operating expenses attributed to the Primexx Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on October 1, 2021 through December 31, 2021.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and 2020 was derived from the historical financial statements of the Company giving effect to the Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for the issuance of the Company’s common stock and the borrowings under the Credit Facility as total consideration, as well as pro forma adjustments based on available information and certain assumptions that the Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Primexx Acquisition taken place on January 1, 2020 and is not intended to be a projection of future results.
| | | | | | | | | | | | | | |
| | Years Ended December 31, |
| | 2021 | | 2020 |
| | (In thousands) |
Revenues | | $2,287,012 | | | $1,228,735 | |
Income (loss) from operations | | 1,145,995 | | | (3,072,237) | |
Net income (loss) | | 477,192 | | | (3,151,443) | |
Basic earnings per common share | | $8.28 | | | ($64.65) | |
Diluted earnings per common share | | $8.04 | | | ($64.65) | |
Non-Core Asset Divestitures. During the second quarter of 2021, the Company completed its divestitures of certain non-core assets in the Delaware Basin for net proceeds of $29.6 million. The divestitures were primarily comprised of natural gas producing properties in the Western Delaware Basin as well as a small undeveloped acreage position.
On November 19, 2021, the Company closed on its divestiture of certain non-core assets in the Eagle Ford Shale, comprised of producing properties as well as an undeveloped acreage position, for net proceeds of $93.4 million, subject to post-closing adjustments.
In the fourth quarter of 2021, the Company closed on the divestiture of certain non-core assets in the Midland Basin, comprised of producing properties as well as an undeveloped acreage position for net proceeds of $30.9 million, subject to post-closing adjustments.
On October 28, 2021, the Company closed on the divestiture of certain non-core water infrastructure for net proceeds of $27.9 million, subject to post-closing adjustments, as well as up to $18.0 million of incremental contingent consideration based on completed lateral length for wells in a specified area.
The aggregate net proceeds for each of the 2021 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
2020 Divestitures
ORRI Transaction. On September 30, 2020, the Company sold an undivided 2.0% (on an 8/8ths basis) overriding royalty interest, proportionately reduced to the Company’s net revenue interest, in and to the Company’s operated leases, excluding certain interests to Chambers Minerals, LLC, a private investment vehicle managed by Kimmeridge Energy, for net proceeds of $135.8 million (“ORRI Transaction”), which were used to repay borrowings outstanding under the Credit Facility.
Non-Operated Working Interest Transaction. On November 2, 2020, the Company sold substantially all of its non-operated assets for net proceeds of approximately $29.6 million, which were used to repay borrowings outstanding under the Credit Facility. The transaction had an effective date of September 1, 2020 and is subject to post-closing adjustments.
The aggregate net proceeds for each of the 2020 divestitures discussed above were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
2019 Acquisitions and Divestitures
Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details.
The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currentlywith information available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determiningat that time.
For the fair valueperiod from the closing date of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The company expects to complete the purchase price allocation during the 12-month period following the acquisition date.
The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
|
| | | | |
| | Preliminary Purchase
Price Allocation
|
| | (In thousands) |
Consideration: | | |
Fair value of the Company’s common stock issued | |
| $765,373 |
|
Total consideration | |
| $765,373 |
|
| | |
Liabilities: | | |
Accounts payable | |
| $37,657 |
|
Revenues and royalties payable | | 52,449 |
|
Operating lease liabilities - current | | 29,924 |
|
Fair value of derivatives - current | | 61,015 |
|
Other current liabilities | | 82,084 |
|
Long-term debt | | 1,984,135 |
|
Operating lease liabilities - non-current | | 30,070 |
|
Asset retirement obligation | | 26,151 |
|
Fair value of derivatives - non-current | | 26,960 |
|
Other long-term liabilities | | 17,260 |
|
Common stock warrants | | 10,029 |
|
Total liabilities assumed | |
| $2,357,734 |
|
| | |
Assets: | | |
Accounts receivable, net | |
| $48,479 |
|
Fair value of derivatives - current | | 17,451 |
|
Other current assets | | 4,945 |
|
Evaluated oil and natural gas properties | | 2,133,280 |
|
Unevaluated properties | | 682,928 |
|
Other property and equipment | | 9,614 |
|
Fair value of derivatives - non-current | | 4,518 |
|
Deferred tax asset | | 159,320 |
|
Operating lease right-of-use-assets | | 59,994 |
|
Other long term assets | | 2,578 |
|
Total assets acquired | |
| $3,123,107 |
|
ApproximatelyCarrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $28.6 million of revenues and $7.0 million of direct operating expenses attributed to the Carrizo Acquisition arewere included in the Company’s consolidated statements of operations for the period from the closing date on December 20, 2019 throughyear ended December 31, 2019.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the yearsyear ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.
Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.
The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.
|
| | | | | | | | |
| | Years Ended December 31, |
| | 2019 | | 2018 |
| | (In thousands) |
Revenues | |
| $1,620,357 |
| |
| $1,661,171 |
|
Income from operations | | 614,668 |
| | 767,628 |
|
Net income | | 369,777 |
| | 734,527 |
|
Basic earnings per common share | | 0.89 |
| |
| $1.87 |
|
Diluted earnings per common share | | 0.89 |
| |
| $1.87 |
|
| | | | | | | | |
| | Year Ended December 31, 2019 |
| | (In thousands) |
Revenues | | $1,620,357 | |
Income from operations | | 614,668 | |
Net income | | 369,777 | |
Basic earnings per common share | | $0.89 | |
Diluted earnings per common share | | $0.89 | |
During 2019, inIn conjunction with the Carrizo Acquisition, the Company incurred costs totaling $28.5 million and $74.4 million for the years ended December 31, 2020 and 2019, respectively, comprised of severance costs of $6.2 million and $28.8 million for the years ended December 31, 2020 and 2019, respectively, and other merger and integration expenses of $22.3 million and $45.6 million. As ofmillion for the years ended December 31, 2020 and 2019, $52.4 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.respectively.
Ranger Divestiture. In the second quarter of 2019, the Company completed its divestiture of certain non-core assets in the southern Midland Basin (the “Ranger Divestiture”) for net cash proceeds of $244.9 million. The transaction also provided for potential additional contingent consideration in payments of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of this contingent consideration arrangement. The divestiture encompasses the Ranger operating area in the southern Midland Basin which includesincluded approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized.
2018 Acquisitions and Divestitures
On August 31, 2018,recognized as the Company completeddivestitures did not significantly alter the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock offering completed on May 30, 2018 and the issuance of the 6.375% Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings.
The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonmentrelationship between capitalized costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
|
| | | |
| Purchase Price Allocation |
| (In thousands) |
Assets | |
Oil and natural gas properties | |
Evaluated properties |
| $253,089 |
|
Unevaluated properties | 287,000 |
|
Total oil and natural gas properties |
| $540,089 |
|
Total assets acquired |
| $540,089 |
|
| |
Liabilities | |
Asset retirement obligations |
| ($570 | ) |
Total liabilities assumed |
| ($570 | ) |
Net Assets Acquired |
| $539,519 |
|
estimated proved reserves.Approximately $27.3 million of revenues and $9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition.
|
| | | | | | | | |
| | Years Ended December 31, |
| | 2018 | | 2017 |
| | (In thousands) |
Revenues | |
| $669,236 |
| |
| $469,896 |
|
Income from operations | | 299,090 |
| | 209,723 |
|
Net income | | 324,318 |
| | 181,406 |
|
Basic earnings per common share | | $1.49 | | $0.90 |
Diluted earnings per common share | | $1.49 | | $0.90 |
Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $87.9 million.
The Company did not have any material divestitures for the year ended December 31, 2018.
2017 Acquisitions and Divestitures
Ameredev Acquisition. On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646.6 million, excluding customary purchase price adjustments (the “Ameredev Acquisition”). The Company partially funded the Ameredev Acquisition with net proceeds from the common stock offering completed on December 19, 2016. The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Acquisition.
The Ameredev Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.
|
| | | |
| Purchase Price Allocation |
| (In thousands) |
Assets | |
Oil and natural gas properties | |
Evaluated properties |
| $137,368 |
|
Unevaluated properties | 509,359 |
|
Total oil and natural gas properties |
| $646,727 |
|
Total assets acquired |
| $646,727 |
|
| |
Liabilities | |
Asset retirement obligations |
| ($168 | ) |
Total liabilities assumed |
| ($168 | ) |
Net Assets Acquired |
| $646,559 |
|
Approximately $36.1 million of revenues and $8.5 million of direct operating expenses attributed to the Ameredev Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on February 13, 2017 through December 31, 2017.
Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Ameredev Acquisition.
|
| | | | |
| | Year Ended December 31, 2017 |
| | (In thousands) |
Revenues | |
| $369,527 |
|
Income from operations | | 144,104 |
|
Net income | | 115,787 |
|
Basic earnings per common share | |
| $0.57 |
|
Diluted earnings per common share | |
| $0.57 |
|
Other. On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Acquisition discussed above, for aggregate net cash consideration of approximately $52.0 million. The Company funded the cash purchase price with available cash and proceeds from the issuance of an additional $200.0 million of its 6.125% Senior Notes. See “Note 7 - Borrowings” for further details of this offering.
The Company did not have any material divestitures for the year ended December 31, 2017.
Note 5 – Property and Equipment, Net
As of December 31, 20192021 and 2018,2020, total property and equipment, net consisted of the following:
| | | | | | | | | | | | | | |
| | As of December 31, |
| | 2021 | | 2020 |
Oil and natural gas properties, full cost accounting method | | (In thousands) |
Evaluated properties | | $9,238,823 | | | $7,894,513 | |
Accumulated depreciation, depletion, amortization and impairments | | (5,886,002) | | | (5,538,803) | |
Evaluated properties, net | | 3,352,821 | | | 2,355,710 | |
Unevaluated properties | | | | |
Unevaluated leasehold and seismic costs | | 1,557,453 | | | 1,532,304 | |
Capitalized interest | | 255,374 | | | 200,946 | |
Total unevaluated properties | | 1,812,827 | | | 1,733,250 | |
Total oil and natural gas properties, net | | $5,165,648 | | | $4,088,960 | |
| | | | |
Other property and equipment | | $58,367 | | | $60,287 | |
Accumulated depreciation | | (30,239) | | | (28,647) | |
Other property and equipment, net | | $28,128 | | | $31,640 | |
|
| | | | | | | | |
| | As of December 31, |
| | 2019 | | 2018 |
Oil and natural gas properties, full cost accounting method | | (In thousands) |
Evaluated properties | |
| $7,203,482 |
| |
| $4,585,020 |
|
Accumulated depreciation, depletion, amortization and impairments | | (2,520,488 | ) | | (2,270,675 | ) |
Net evaluated oil and natural gas properties | | 4,682,994 |
| | 2,314,345 |
|
Unevaluated properties | | | | |
Unevaluated leasehold and seismic costs | | 1,843,725 |
| | 1,316,190 |
|
Capitalized interest | | 142,399 |
| | 88,323 |
|
Total unevaluated properties | | 1,986,124 |
| | 1,404,513 |
|
Total oil and natural gas properties, net | |
| $6,669,118 |
| |
| $3,718,858 |
|
| | | | |
Other property and equipment | |
| $67,202 |
| |
| $38,463 |
|
Accumulated depreciation | | (31,949 | ) | | (16,562 | ) |
Other property and equipment, net | |
| $35,253 |
| |
| $21,901 |
|
The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $36.2$47.4 million $28.0 millionfor the year ended December 31, 2021 and $20.3$36.2 million for the years ended December 31, 2019, 20182020 and 2017, respectively. 2019.
The Company capitalized interest costs to unproved properties totaling $78.5$99.6 million, $56.2$88.6 million and $33.8$78.5 million for the years ended December 31, 2021, 2020 and 2019, 2018respectively.
Impairment of Evaluated Oil and 2017, respectively.Gas Properties
The Company did not recognize impairments of evaluated oil and gas properties for the years ended December 31, 2021 and 2019. Primarily as a result of the significant reduction in the 12-Month Average Realized Price of crude oil, the Company recognized impairments of evaluated oil and gas properties of $2.5 billion for the year December 31, 2020.
Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2021, 2020, and 2019 are summarized in the table below:
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| Years Ended December 31, |
| 2021 | | 2020 | | 2019 |
Impairment of evaluated oil and natural gas properties (In thousands) | $— | | $2,547,241 | | $— |
Beginning of period 12-Month Average Realized Price ($/Bbl) | $37.44 | | $53.90 | | $58.40 |
End of period 12-Month Average Realized Price ($/Bbl) | $65.44 | | $37.44 | | $53.90 |
Percent increase (decrease) in 12-Month Average Realized Price | 75 | % | | (31 | %) | | (8 | %) |
Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of2021 were incurred in the following:following periods:
|
| | | | | | | | | | | | | | | | | | | | |
| | 2019 | | 2018 | | 2017 | | 2016 | | Total |
| | (In thousands) |
Acquisition costs | |
| $682,413 |
| |
| $383,238 |
| |
| $577,959 |
| |
| $115,833 |
| |
| $1,759,443 |
|
Exploration costs | | 43,174 |
| | 22,384 |
| | 18,724 |
| | — |
| | 84,282 |
|
Capitalized interest | | 78,492 |
| | 56,151 |
| | 7,756 |
| | — |
| | 142,399 |
|
Total unevaluated properties | |
| $804,079 |
| |
| $461,773 |
| |
| $604,439 |
| |
| $115,833 |
| |
| $1,986,124 |
|
| | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | | |
| | 2021 | | 2020 | | 2019 | | 2018 and Prior | | Total |
| | (In thousands) |
Unevaluated property costs | | $401,403 | | | $113,079 | | | $479,836 | | | $818,509 | | | $1,812,827 | |
Note 6 – Earnings Per Share
Basic earnings (loss) per share is computed by dividing income (loss) available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares and unexercised warrants outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. For the year ended December 31, 2020, the Company reported a loss available to common stockholders. As a result, the calculation of diluted weighted average common shares outstanding excluded all potentially dilutive common shares outstanding.
The following table sets forth the computation of basic and diluted earnings per share:
| | | | | | | | | | Years Ended December 31, |
| | Years Ended December 31, | | 2021 | | 2020 | | 2019 |
| | 2019 | | 2018 | | 2017 | | (In thousands, except per share amounts) |
| | (In thousands, except per share amounts) | |
Net income | |
| $67,928 |
| |
| $300,360 |
| |
| $120,424 |
| |
Preferred stock dividends | | (3,997 | ) | | (7,295 | ) | | (7,295 | ) | |
Net Income (Loss) | | Net Income (Loss) | | $365,151 | | | ($2,533,621) | | | $67,928 | |
Preferred stock dividends (1) | | Preferred stock dividends (1) | | — | | | — | | | (3,997) | |
Loss on redemption of preferred stock | | (8,304 | ) | | — |
| | — |
| Loss on redemption of preferred stock | | — | | | — | | | (8,304) | |
Income available to common stockholders | |
| $55,627 |
| |
| $293,065 |
| |
| $113,129 |
| |
Income (Loss) Available to Common Stockholders | | Income (Loss) Available to Common Stockholders | | $365,151 | | | ($2,533,621) | | | $55,627 | |
| | | | | | | | | | | | |
Basic weighted average common shares outstanding | | 233,140 |
| | 216,941 |
| | 201,526 |
| Basic weighted average common shares outstanding | | 48,612 | | | 39,718 | | | 23,313 | |
Dilutive impact of restricted stock | | 410 |
| | 655 |
| | 576 |
| Dilutive impact of restricted stock | | 296 | | | — | | | 27 | |
Dilutive impact of warrants | | Dilutive impact of warrants | | 1,403 | | | — | | | — | |
Diluted weighted average common shares outstanding | | 233,550 |
| | 217,596 |
| | 202,102 |
| Diluted weighted average common shares outstanding | | 50,311 | | | 39,718 | | | 23,340 | |
| | | | | | | | | | | | |
Income Available to Common Stockholders Per Common Share | | | | | | | |
Income (Loss) Available to Common Stockholders Per Common Share | | Income (Loss) Available to Common Stockholders Per Common Share | |
Basic | |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
| Basic | | $7.51 | | | ($63.79) | | | $2.39 | |
Diluted | |
| $0.24 |
| |
| $1.35 |
| |
| $0.56 |
| Diluted | | $7.26 | | | ($63.79) | | | $2.38 | |
| | | | | | | |
Restricted stock (1)(2) | | 998 |
| | 89 |
| | 16 |
| | 7 | | | 581 | | 90 |
Warrants (2) | | Warrants (2) | | 481 | | | 2,564 | | | 9 |