PART I.
Overview
Callon Petroleum Company has been engaged in the exploration, development, acquisition and production of oil and natural gas properties since 1950. 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.
We are an independent oil and natural gas company focused on the acquisition, development, exploration and exploitationdevelopment of unconventional onshorehigh-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 Basin in West Texas, as well as the Eagle Ford in South Texas. Our primary operations in the Permian reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow-generating business in the Eagle Ford.
Major Developments in 2021
Financing and Liquidity Highlights
•We decreased our total outstanding long-term debt principal balance by approximately 10% to $2.7 billion as of December 31, 2021, from $3.0 billion as of December 31, 2020.
•As of December 31, 2021, our senior secured revolving credit facility (“Credit Facility”) had a borrowing base and elected commitment amount of $1.6 billion with borrowings outstanding of $785.0 million, representing less than 50% of our borrowing base.
•On November 5, 2021, we completed the exchange of $197.0 million in aggregate principal amount of our 9.00% Second Lien Senior Secured Notes due 2025 (the “Second Lien Notes”) for 5.5 million shares of our common stock (the “Second Lien Note Exchange”).
•On July 6, 2021, we issued $650.0 million in aggregate principal amount of our 8.00% senior unsecured notes due 2028 (the “8.00% Senior Notes”) in a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. We used a portion of the net proceeds from the 8.00% Senior Notes to redeem all $542.7 million of our outstanding 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”) and the remaining proceeds to partially repay amounts outstanding under our Credit Facility.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for further discussion.
Primexx Acquisition. On October 1, 2021, we completed the acquisition of certain producing oil and natural gas reservesproperties, undeveloped acreage and associated infrastructure assets in the Delaware Basin from Primexx Resource Development, LLC and BPP Acquisition, LLC (the “Primexx Acquisition”) for total consideration of $880.8 million. Additionally, certain interest owners exercised their option to sell their interest in the properties included in the Primexx Acquisition to us for consideration structured similarly to the Primexx Acquisition, for an incremental purchase price totaling approximately $33.1 million. These transactions added approximately 37,000 net acres to our portfolio in the Permian Basin. The Permian Basin is locatedSee “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion.
Non-Core Asset Divestitures. During 2021, we completed divestitures of certain non-core assets in West Texas and southeastern New Mexico and is comprised of three primary sub-basins: the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and enteredEagle Ford Shale as well as the Delaware Basin through an acquisition completed in February 2017. Our drilling activity during 2017 was predominantly focused on the horizontal developmentdivestiture of several prospective intervals in the Midland Basin, including multiple levelscertain non-core water infrastructure for total net proceeds of $181.8 million, subject to post-closing adjustments, and up to $18.0 million of incremental contingent consideration. See “Note 4 – Acquisitions and Divestitures” of the Wolfcamp formation and the Lower Spraberry shales. As a result ofNotes to our horizontal development efforts and contributions from acquisitions, our net daily productionConsolidated Financial Statements for calendar year 2017 as compared to calendar year 2016 grew approximately 50% to 22,940 BOE/d (approximately 78% oil). We intend to grow our reserves and production through the development, exploitation and drilling of our multi-year inventory of identified, potential drilling locations. We intend to add to this inventory through delineation drilling of emerging zones on our existing acreage and acquisition of additional locations through leasehold purchases, leasing programs, joint ventures and asset swaps.further discussion.
| Producing Wells | Producing | ||||||||||||||||
| Horizontal | Vertical | Horizontal Flow | |||||||||||||||
| Net Acres | Gross | Net | Gross | Net | Unit Zones | ||||||||||||
| Midland Basin: | |||||||||||||||||
| Monarch | 7,854 | 68 | 49.9 | 175 | 131.4 | Middle Spraberry Lower Spraberry Wolfcamp A Wolfcamp B | |||||||||||
| Ranger | 8,113 | 54 | 41.8 | 16 | 12.2 | Lower Spraberry Wolfcamp A Upper Wolfcamp B Lower Wolfcamp B | |||||||||||
| Wildhorse | 20,160 | 54 | 39.3 | 76 | 65.7 | Lower Spraberry Wolfcamp A Wolfcamp B | |||||||||||
| Other Permian | 2,528 | 18 | 15.5 | 8 | 8.0 | Wolfcamp A Upper Wolfcamp B Lower Wolfcamp B | |||||||||||
| Total Midland Basin: | 38,655 | 194 | 146.5 | 275 | 217.3 | ||||||||||||
| Delaware Basin: | |||||||||||||||||
| Spur | 18,826 | 38 | 25.3 | 37 | 35.2 | Third Bone Spring Upper Wolfcamp A Lower Wolfcamp A Wolfcamp B | |||||||||||
| Total Permian Basin | 57,481 | 232 | 171.8 | 312 | 252.5 | ||||||||||||
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Our principal objective is to enhance shareholder value through capital efficient development of 7,031 gross (2,488 net) acresour proved reserves, management of our operating costs, and maximization of cash flows while acting as a responsible corporate citizen in the Delaware Basin, located nearareas in which we operate. Key elements of the execution of this strategy include:
•Optimizing the development of our multi-zone resource base through thoughtful plans for life of field development that are informed by extensive analysis of subsurface data and empirical well results;
•Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities;
•Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure;
•Maximizing and preserving our inventory of well locations through selective delineation of emerging targets on our existing acreage acquired inpositions and scaled development of proven areas to minimize potential degradation of future drilling locations;
•Integrating sustainable business practices that minimize our impact on the Ameredev Transaction discussed above, for totalenvironment, empower and develop a diverse workforce, and enrich our communities; and
•Enhancing our financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and generating free cash consideration of $52.5 million, excluding customary purchase price adjustments.flow to reduce leverage.
Our Strengths
We own additional immaterial properties in Louisiana.believe the following attributes position Callon to achieve its objectives:
•Quality Assets - High quality Permian asset base with several years of a barrel of oilproven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling and a Mcfmore mature asset base in the Eagle Ford which has lower operational risk and generates repeatable, profitable well results;
•Operational Control - High degree of natural gas. The price ofoperational control that allows us to efficiently maximize value through daily and long-term decisions that drive our strategy;
•Talented Workforce - Dedicated and experienced employee base working within a barrel of oilcollaborative culture to achieve both personal and collective goals; and
•Sustainable Business Practices - Focus on value creation in a responsible manner by utilizing an operating philosophy that provides our employees a safe workplace while at the same time conducting operations in a manner that seeks to reduce our impact on the environment. See our Sustainability Report published on our company website (www.callon.com) for performance highlights and additional information. Information contained in our Sustainability Report is much higher than the price of six Mcf of natural gas, so the ratio of six Mcf to one BOEnot incorporated by reference into, and does not reflect the economic equivalentconstitute a part of, a barrelthis 2021 Annual Report on Form 10-K.
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Oil and Natural GasProperties
Summary of oil to six Mcf of gas.2021 Proved Reserves, Production and Drilling by Region
| Permian | Eagle Ford | Total | ||||||||||||||||||||||||||||||||||||
| Proved reserves | ||||||||||||||||||||||||||||||||||||||
| Crude oil (MBbls) | 235,450 | 54,846 | 290,296 | |||||||||||||||||||||||||||||||||||
| Natural gas (MMcf) | 523,435 | 53,892 | 577,327 | |||||||||||||||||||||||||||||||||||
| NGLs (MBbls) | 88,707 | 9,397 | 98,104 | |||||||||||||||||||||||||||||||||||
| Total proved reserves (MBoe) | 411,396 | 73,225 | 484,621 | |||||||||||||||||||||||||||||||||||
| Proved reserves by classification (MBoe) | ||||||||||||||||||||||||||||||||||||||
| Proved developed | 222,105 | 51,878 | 273,983 | |||||||||||||||||||||||||||||||||||
| Proved undeveloped | 189,291 | 21,347 | 210,638 | |||||||||||||||||||||||||||||||||||
| Total proved reserves (MBoe) | 411,396 | 73,225 | 484,621 | |||||||||||||||||||||||||||||||||||
| Percent of proved developed reserves | 81 | % | 19 | % | 100 | % | ||||||||||||||||||||||||||||||||
| Percent of proved undeveloped reserves | 90 | % | 10 | % | 100 | % | ||||||||||||||||||||||||||||||||
| Percent of total reserves | 85 | % | 15 | % | 100 | % | ||||||||||||||||||||||||||||||||
| Production volumes | Total | Per Day | Total | Per Day | Total | Per Day | ||||||||||||||||||||||||||||||||
| Crude oil (MBbls and Bbls/d) | 14,475 | 39,658 | 7,749 | 21,229 | 22,224 | 60,887 | ||||||||||||||||||||||||||||||||
| Natural gas (MMcf and Mcf/d) | 29,682 | 81,320 | 7,704 | 21,107 | 37,386 | 102,427 | ||||||||||||||||||||||||||||||||
| NGLs (MBbls and Bbls/d) | 5,155 | 14,123 | 1,284 | 3,518 | 6,439 | 17,641 | ||||||||||||||||||||||||||||||||
| Total production volumes (MBoe and Boe/d) | 24,577 | 67,334 | 10,317 | 28,265 | 34,894 | 95,599 | ||||||||||||||||||||||||||||||||
| Percent of total production | 70 | % | 30 | % | 100 | % | ||||||||||||||||||||||||||||||||
| Permian | Eagle Ford | Total | ||||||||||||||||||||||||||||||||||||
| Operated Well Data | Gross | Net | Gross | Net | Gross | Net | ||||||||||||||||||||||||||||||||
| Drilled | 54 | 47.5 | 14 | 13.8 | 68 | 61.3 | ||||||||||||||||||||||||||||||||
| Completed | 67 | 59.0 | 45 | 44.8 | 112 | 103.8 | ||||||||||||||||||||||||||||||||
| As of December 31, 2021 | ||||||||||||||||||||||||||||||||||||||
| Drilled but uncompleted | 21 | 19.4 | 6 | 5.8 | 27 | 25.2 | ||||||||||||||||||||||||||||||||
| Producing | 738 | 654.3 | 588 | 532.8 | 1,326 | 1,187.1 | ||||||||||||||||||||||||||||||||
Gas Reserves
The following table sets forth certainsummary information aboutwith respect to our estimated net proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2021, 2020, and 2019. For each year in the table below, the estimated proved reserves were prepared by ourDeGolyer and MacNaughton (“D&M”), Callon’s independent petroleumthird party reserve engineers. Allengineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition in late 2019, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. For further information concerning D&M’s estimates of our proved reserves are locatedas of December 31, 2021, see the reserve report included as an exhibit to this 2021 Annual Report on Form 10-K. In accordance with SEC rules, we used the 12-Month Average Realized Price of oil, NGLs, and natural gas in the Permian Basin in the continental United States.
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| For the Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Proved developed | |||||||||||
| Oil (MBbls) | 51,920 | 32,920 | 22,257 | ||||||||
| Natural gas (MMcf) | 104,389 | 61,871 | 38,157 | ||||||||
| MBOE | 69,318 | 43,232 | 28,617 | ||||||||
| Proved undeveloped | |||||||||||
| Oil (MBbls) | 55,152 | 38,225 | 21,091 | ||||||||
| Natural gas (MMcf) | 75,021 | 60,740 | 27,380 | ||||||||
| MBOE | 67,656 | 48,348 | 25,654 | ||||||||
| Total proved | |||||||||||
| Oil (MBbls) | 107,072 | 71,145 | 43,348 | ||||||||
| Natural gas (MMcf) | 179,410 | 122,611 | 65,537 | ||||||||
| MBOE | 136,974 | 91,580 | 54,271 | ||||||||
| Financial Information (in thousands) | |||||||||||
Estimated pre-tax future net cash flows (a) | $ | 3,546,509 | $ | 1,821,221 | $ | 1,160,808 | |||||
Pre-tax discounted present value (a) (b) | $ | 1,576,755 | $ | 809,832 | $ | 570,906 | |||||
Standardized measure of discounted future net cash flows (a) (b) | $ | 1,556,682 | $ | 809,832 | $ | 570,890 | |||||
| As of December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
Proved developed reserves (1) | ||||||||||||||||||||
| Crude oil (MBbls) | 162,886 | 128,923 | 152,687 | |||||||||||||||||
| Natural gas (MMcf) | 332,266 | 238,119 | 320,676 | |||||||||||||||||
| NGLs (MBbls) | 55,720 | 43,315 | 24,844 | |||||||||||||||||
| Total proved developed reserves (MBoe) | 273,983 | 211,925 | 230,977 | |||||||||||||||||
Proved undeveloped reserves (1) | ||||||||||||||||||||
| Crude oil (MBbls) | 127,410 | 160,564 | 193,674 | |||||||||||||||||
| Natural gas (MMcf) | 245,061 | 303,479 | 436,458 | |||||||||||||||||
| NGLs (MBbls) | 42,384 | 52,811 | 42,618 | |||||||||||||||||
| Total proved undeveloped reserves (MBoe) | 210,638 | 263,954 | 309,035 | |||||||||||||||||
Total proved reserves (1) | ||||||||||||||||||||
| Crude oil (MBbls) | 290,296 | 289,487 | 346,361 | |||||||||||||||||
| Natural gas (MMcf) | 577,327 | 541,598 | 757,134 | |||||||||||||||||
| NGLs (MBbls) | 98,104 | 96,126 | 67,462 | |||||||||||||||||
| Total proved reserves (MBoe) | 484,621 | 475,879 | 540,012 | |||||||||||||||||
| Proved developed reserves % | 57 | % | 45 | % | 43 | % | ||||||||||||||
| Proved undeveloped reserves % | 43 | % | 55 | % | 57 | % | ||||||||||||||
| 12-Month Average Realized Prices | ||||||||||||||||||||
| Crude oil ($/Bbl) | $65.44 | $37.44 | $53.90 | |||||||||||||||||
| Natural gas ($/Mcf) | $3.31 | $1.02 | $1.55 | |||||||||||||||||
| NGLs ($/Bbl) | $29.19 | $11.10 | $15.58 | |||||||||||||||||
| Standardized measure of discounted future net cash flows (GAAP) (in millions) | $6,250.8 | $2,310.4 | $4,951.0 | |||||||||||||||||
| PV-10 (Non-GAAP) (in millions): | ||||||||||||||||||||
| Proved developed PV-10 | $4,502.6 | $1,577.3 | $3,246.8 | |||||||||||||||||
| Proved undeveloped PV-10 | 2,548.7 | 767.7 | 2,122.8 | |||||||||||||||||
| Total PV-10 (Non-GAAP) | $7,051.3 | $2,345.0 | $5,369.6 | |||||||||||||||||
(1) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, reserve volumes for NGLs and natural gas are presented separately for periods subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, we presented our reserve volumes for NGLs with natural gas.
Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)
We believe that the presentation of PV-10 provides greater comparability when evaluating oil and gas companies due to the many factors unique to each individual company that impact the amount and timing of future income taxes. In addition, we believe that PV-10 is widely used by investors and analysts as a basis for comparing the relative size and value of our proved reserves to other oil and gas companies. PV-10 should not be considered in isolation or as a substitute for the standardized measure of discounted future net cash flows or any other measure of a company’s financial or operating performance presented in accordance with GAAP. Neither PV-10 nor the standardized measure of discounted future net cash flows purport to represent the fair value of our proved oil and gas reserves.
| As of December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In millions) | ||||||||||||||||||||
| Standardized measure of discounted future net cash flows (GAAP) | $6,250.8 | $2,310.4 | $4,951.0 | |||||||||||||||||
| Add: present value of future income taxes discounted at 10% per annum | 800.5 | 34.6 | 418.6 | |||||||||||||||||
| PV-10 (Non-GAAP) | $7,051.3 | $2,345.0 | $5,369.6 | |||||||||||||||||
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Proved Reserves
Our reserve estimates are conducted from fundamental petrophysical, geological, engineering, financial and accounting data. Reserves are estimated based on production decline analysis, analogy to producing offsets, detailed reservoir modeling, volumetric calculations or a combination of these methods, in all cases having regard to economic considerations and using technologies that have been demonstrated in the field to yield repeatable and consistent results as defined in the SEC regulations. To establish reasonable certainty of our proved reserves estimates, including material additions to our proved reserves, we use certain technologies and economic data, including production and well test data, historical well costs and operating data, geologic and seismic data, and subsurface information obtained through wellbores such as electrical logs, radioactive logs, reservoir core samples, fluid samples, and static and dynamic pressure information. Non-producing reserves are estimated by analogy to producing offsets, with consideration given to a development plan approved by Callon’s management.
As of December 31, 2021, our estimated proved reserves totaled 484.6 MMBoe, an increase of 2% from the prior year end, and included 290.3 MMBbls of oil, 577.3 Bcf of natural gas and 98.1 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $6.3 billion. Oil constituted approximately 60% of our total estimated proved reserves as well as our total estimated proved developed reserves. The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2021.
| Total (MBoe) | ||||||||
| Proved reserves as of December 31, | 475,879 | |||||||
| Extensions and discoveries | 36,180 | |||||||
| Revisions to previous estimates | (14,181) | |||||||
| Purchase of | 57,652 | |||||||
| Sales of | (36,015) | |||||||
| Production | (34,894) | |||||||
| Proved reserves as of | 484,621 | |||||||
•Extensions and Discoveries. We added 36.2 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas. See the year were due to (1) 47.4 MMBOE related totable below for the Company’s horizontal developmentimpact of a portion of its properties (2) 10.5 MMBOE related to acquired properties (3) 2.2 MMBOE in upward revisions primarily at ourextensions and discoveries on total proved developed locations. These increases were partially offset by (1) 8.4 MMBOE related to the Company’s production during 2017 and (2) 6.4 MMBOE of revisions due to the removal of 13 proved undeveloped locations as a result of a change in our development and drilling plans within our operating areas and the removal of certain proved developed vertical well locations.reserves for 2021:
| Extensions and discoveries | Total (MBoe) | |||||||
| Total proved | 36,180 | |||||||
| Proved undeveloped | 26,044 | |||||||
Difference (Proved developed producing)(1) | 10,136 | |||||||
(1) These extensions and discoveries were not recognized as proved undeveloped reserves in a prior period, but rather were recognized directly as proved developed producing reserves as there was not an offset proved developed producing location at the time of drilling in order to classify as a proved undeveloped location.
We incurred costs of $87.0 million for the extensions and discoveries associated with proved developed producing wells and $52.7 million on facilities associated with proved developed producing wells during 2021.
•Revisions to Previous Estimates. The table below shows the components of the net negative revisions of previous estimates of 14.2 MMBoe.
| Total (MBoe) | ||||||||
Pricing(1) | 27,932 | |||||||
PUDs removed due to changes in development plan(2) | (29,016) | |||||||
Performance(3) | (13,097) | |||||||
| Total revisions to previous estimates | (14,181) | |||||||
(1) Primarily as a result of the change in 12-Month Average Realized Price of crude oil, which increased approximately 75% as compared to December 31, 2020.
(2) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window.
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(3) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.
•Purchase of Reserves in Place. The 57.7 MMBoe of purchases of reserves in place was associated with the Primexx Acquisition. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion.
•Sales of Reserves in Place. The 36.0 MMBoe of sales of reserves in place were primarily associated with the divestitures of non-core assets in the Western Delaware Basin in the second quarter of 2021 and the Eagle Ford Shale and Midland Basin in the fourth quarter of 2021. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion.
Proved Undeveloped Reserves
Annually, the Company reviews its proved undeveloped reserves (“PUDs”)we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if the Company haswe have plans to convert these reserves into proved developed producing reserves (“PDPs”)PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2018 capital budget2022 Capital Budget, as defined below, and, in subsequent years, the allocation of capital within our long-range business plan to convert PUDs to PDPs within this fivefive-year period. The following table provides a summary of the changes in our PUDs for the year period. In general,ended December 31, 2021.
| Total (MBoe) | ||||||||
| PUDs as of December 31, 2020 | 263,954 | |||||||
| Extensions and discoveries | 26,044 | |||||||
| Revisions to previous estimates | (34,235) | |||||||
| Purchases of reserves in place | 14,960 | |||||||
| Sales of reserves in place | (21,205) | |||||||
| Converted to proved developed | (38,880) | |||||||
| PUDs as of December 31, 2021 | 210,638 | |||||||
•Extensions and Discoveries. We added 26.0 MMBoe of new reserves in extensions and discoveries as a result of additional offset locations associated with our 2018drilling program.
•Revisions to Previous Estimates. The table below shows the components of the net negative revisions of previous estimates of 34.2 MMBoe.
| Total (MBoe) | ||||||||
Pricing(1) | 3,541 | |||||||
PUDs removed due to changes in development plan(2) | (29,016) | |||||||
Performance(3) | (8,760) | |||||||
| Total revisions to previous estimates | (34,235) | |||||||
(1) Primarily as a result of the change in 12-Month Average Realized Price of crude oil, which increased by approximately 75% as compared to December 31, 2020.
(2) Removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital budgetefficiency and our long-range capital plans are primarily governed by our expectations of internally generated cash flow borrowing availability under our senior secured revolving credit facility (“Credit Facility”) and corporate credit metrics. Reserve calculations at any end-of-year period are representative ofgeneration as well as changes in our development plans, at that time. Changes in commodity pricing, oilfield service costs and availability, and other economic factors may lead to changes in development plans.
(3) Primarily related to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.
•Sales of Reserves in Place. The 21.2 MMBoe of sales of reserves in place were associated with the divestitures of non-core assets in the Eagle Ford Shale and Midland Basin in the fourth quarter of 2021. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion.
•Converted to Proved Developed. During 2021, we converted 38.9 MMBoe of PUDs that were booked as PUDs as of December 31, 2020 to proved developed at a cost of $210.2 million, or $5.41 per Boe. During 2021, our PUD locationsconversion was below 20% primarily as a result of a changethe removal of PUDs due to the changes in development plans discussed above. We currently estimate that we will convert over 50% of our PUDs as of December 31, 2021 in 2022 and 2023.
During 2021, we also incurred $47.0 million on PUDs that were drilled but uncompleted as of December 31, 2021. As of December 31, 2021, we had 9.0 MMBoe of PUDs associated with drilled but uncompleted wells. All of the Company’s developmentreserves associated with drilled but uncompleted wells are scheduled to be completed in 2022. We expect to incur approximately $43.3 million of capital expenditures to
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complete these wells. We also incurred $72.9 million on wells in progress and drilling plans within its operating areas and downward revisions to its current PUD locations. In addition, these increases$20.5 million converting PUDs that were offset by the reclassification of 8.3 MMBOE, or 17%, included in the year-end 2016 PUDs, to PDPs as a result of our horizontal development of properties at a total cost of approximately $57.0 million, net. divestitures in 2021.
Qualifications of Technical Persons
Our internal director of reserves has over 20 years of experience in the petroleum industry and extensive experience in the estimation of reserves and the review of reserve reports prepared by third party engineering firms. Compliance as it relates to reporting the Company’s reserves is the responsibility of our Chief Operating Officer, who has over 35 years of industry experience, including 29 years as a manager, and is also our principal engineer. InHe has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to his years of experience, our principal engineer holds a degreeM.S. in petroleum engineeringEnvironmental and Planning Engineering, and is experienced in asset evaluation and management.
Internal Controls Over Reserve Estimation Process
are assessed for effectiveness annually.
To further enhance the control environment over the reserve estimation process, our Strategic PlanningOperations and Reserves Committee, aan independent committee of the BoardCompany’s board of Directors,directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of the Company’sour oil and natural gas reserves and the work of ourthe independent third party reserve engineer.engineers. The Operations and Reserves Committee’s charter also specifies that the Committeeit shall perform, in consultation with the Company’s management and senior reserves and reservoir engineering personnel, the following responsibilities:
•Oversee the appointment, qualification, independence, compensation and retention of the independent petroleum and geological firm (the “Reserve Firm”)third party reserve engineers engaged by the Company (including resolution of material disagreements between management and the Reserve Firmindependent third party reserve engineers regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Operations and Reserves Committee shall review any proposed changes in the appointment of the Reserve Firm,independent third party reserve engineers, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Firmindependent third party reserve engineers and management.
•Review the Company’s significant reserves engineering principles and policies and any material changes thereto, and any proposed changes in reserves engineering standards and principles which have, or may have, a material impact on the Company’s reserves disclosure.
•Review with management and the Reserve Firmindependent third party reserve engineers the proved reserves of the Company, and, if appropriate, the probable reserves, possible reserves and the total reserves of the Company, including: (i) reviewing significant changes from prior period reports; (ii) reviewing key assumptions used or relied upon by the Reserve Firm;independent third party reserve engineers; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Firmindependent third party reserve engineers and the Company relative to the Company’s peers in the industry; and (iv) reviewing any material reserves adjustments and significant differences between the Company’s and Reserve Firm’sindependent third party reserve engineers’ estimates.
•If the Operations and Reserves Committee deems it necessary, it shall meet in executive session with management and the Reserve Firmindependent third party reserve engineers to discuss the oil and gas reserve determination process and related public disclosures, and any other matters of concern in respect of the evaluation of the reserves.
During our last fiscal year, we filed no reports with other federal agencies which contain an estimate of total proved net oil and natural gas reserves.
See “Item 8. Financial Statements and Supplementary Data - Supplemental Information on Oil and Natural Gas Operations” for additional information regarding our estimated proved reserves and the present value of estimated future net revenues from these proved reserves.
CapitalBudget
Our Board approved an operational capital budget for 2018 has been establishedexpenditures of $725.0 million (the “2022 Capital Budget”), with approximately 80% directed towards drilling, completion, and equipment expenditures. Our scaled development plan for 2022 will continue to employ our life of field development strategy, whereby capital is allocated towards full development plans of depletion and optimal usage of infrastructure. Over 85% of the 2022 Capital Budget is allocated to development in the range of $500 to $540 million on an accrual, or GAAP, basis, inclusive of a planned transition from a four-rig program that commencedPermian with the balance for development in July 2017 to a five-rig program by mid-February 2018.
Eagle Ford.
Our revenues, earnings, liquidity and ability to growliquidity are substantially dependent on the prices we receive for, and our ability to develop, our reserves of oil and natural gas. We believe that we are positioned to execute on our strategy even during downturns in the long-term outlook for our business is favorableindustry due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, 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.
| Years Ended December 31, | ||||||||||||||||||||||||||||||||||||||
| 2021 | 2020 | 2019 (1) | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| Extension Wells - Productive | 19 | 17.2 | 22 | 16.0 | 56 | 36.7 | ||||||||||||||||||||||||||||||||
| Extension Wells - Non-productive | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
| Development Wells - Productive | 93 | 86.7 | 73 | 66.0 | 15 | 11.6 | ||||||||||||||||||||||||||||||||
| Development Wells - Non-productive | — | — | — | — | — | — | ||||||||||||||||||||||||||||||||
(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
Productive Wells
The following table sets forth the Company’s drilled wells, nonenumber of which wereproductive crude oil and natural gas or nonproductive for the periods reflected:
2017 (a) | 2016 | 2015 | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||
| Oil wells | ||||||||||||||||||
Development (b) | 15 | 10.7 | 9 | 4.9 | 14 | 11.4 | ||||||||||||
Exploratory (c) | 33 | 26.5 | 20 | 16.0 | 22 | 15.7 | ||||||||||||
| Total | 48 | 37.2 | 29 | 20.9 | 36 | 27.1 | ||||||||||||
| Crude Oil | Natural Gas | Total | ||||||||||||||||||||||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||||||||||||||||||||||
| Permian - Operated | 919 | 814.8 | 99 | 84.9 | 1,018 | 899.7 | ||||||||||||||||||||||||||||||||
| Permian - Non-operated | 46 | 5.7 | 6 | 0.6 | 52 | 6.3 | ||||||||||||||||||||||||||||||||
| Total Permian | 965 | 820.5 | 105 | 85.5 | 1,070 | 906.0 | ||||||||||||||||||||||||||||||||
| Eagle Ford - Operated | 532 | 480.2 | 77 | 69.7 | 609 | 549.9 | ||||||||||||||||||||||||||||||||
| Eagle Ford - Non-operated | 13 | 0.8 | — | — | 13 | 0.8 | ||||||||||||||||||||||||||||||||
| Total Eagle Ford | 545 | 481.0 | 77 | 69.7 | 622 | 550.7 | ||||||||||||||||||||||||||||||||
| Total | 1,510 | 1,301.5 | 182 | 155.2 | 1,692 | 1,456.7 | ||||||||||||||||||||||||||||||||
Production Volumes, Average Sales Prices and Operating Costs
The following table setstables 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, | ||||||||||||||||||||
| 2021 | 2020 | 2019 (1) | ||||||||||||||||||
Total production (2) | ||||||||||||||||||||
| Oil (MBbls) | ||||||||||||||||||||
| Permian | 14,475 | 14,113 | 11,365 | |||||||||||||||||
| Eagle Ford | 7,749 | 9,430 | 300 | |||||||||||||||||
| Total oil | 22,224 | 23,543 | 11,665 | |||||||||||||||||
| Natural gas (MMcf) | ||||||||||||||||||||
| Permian | 29,682 | 32,087 | 19,484 | |||||||||||||||||
| Eagle Ford | 7,704 | 8,714 | 234 | |||||||||||||||||
| Total natural gas | 37,386 | 40,801 | 19,718 | |||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||
| Permian | 5,155 | 5,390 | 93 | |||||||||||||||||
| Eagle Ford | 1,284 | 1,460 | 42 | |||||||||||||||||
| Total NGLs | 6,439 | 6,850 | 135 | |||||||||||||||||
| Total production (MBoe) | ||||||||||||||||||||
| Permian | 24,577 | 24,851 | 14,705 | |||||||||||||||||
| Eagle Ford | 10,317 | 12,342 | 381 | |||||||||||||||||
| Total barrels of oil equivalent | 34,894 | 37,193 | 15,086 | |||||||||||||||||
Average realized sales price (2) (excluding impact of derivative settlements) | ||||||||||||||||||||
| Oil (per Bbl) | $68.22 | $36.13 | $54.27 | |||||||||||||||||
| Natural gas (per Mcf) | 3.78 | 1.27 | 1.85 | |||||||||||||||||
| NGL (per Bbl) | 30.11 | 11.87 | 15.37 | |||||||||||||||||
| Total average realized sales price (per Boe) | $53.06 | $26.45 | $44.52 | |||||||||||||||||
| Operating costs per Boe | ||||||||||||||||||||
| Lease operating expense | $5.82 | $5.22 | $6.09 | |||||||||||||||||
| Production and ad valorem taxes | $2.87 | $1.68 | $2.83 | |||||||||||||||||
| Gathering, transportation and processing | $2.32 | $2.08 | $— | |||||||||||||||||
(1) Includes activity on properties acquired in the Carrizo Acquisition subsequent to the December 20, 2019 closing date.
(2) Effective January 1, 2020, certain of our natural gas processing agreements were modified to allow us to take title to NGLs resulting from the processing of our natural gas. As a result, sales volumes and prices for NGLs and natural gas are presented separately for the periods indicated (dollars in thousands,subsequent to January 1, 2020. For periods prior to January 1, 2020, except per unit data).for sales volumes and prices specifically associated with Carrizo, we presented our sales volumes and prices for NGLs with natural gas.
14
| For the Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Production | ||||||||||||
| Oil (MBbls) | 6,557 | 4,280 | 2,789 | |||||||||
| Natural gas (MMcf) | 10,896 | 7,758 | 4,312 | |||||||||
| Total (MBOE) | 8,373 | 5,573 | 3,508 | |||||||||
| Revenues | ||||||||||||
| Oil revenue | $ | 322,374 | $ | 177,652 | $ | 125,166 | ||||||
| Natural gas revenue | 44,100 | 23,199 | 12,346 | |||||||||
| Total | $ | 366,474 | $ | 200,851 | $ | 137,512 | ||||||
| Operating costs | ||||||||||||
| Lease operating expense | $ | 49,907 | $ | 38,353 | $ | 27,036 | ||||||
| Production taxes | 22,396 | 11,870 | 9,793 | |||||||||
| Total | $ | 72,303 | $ | 50,223 | $ | 36,829 | ||||||
Average realized sales price (excluding impact of cash settled derivatives) | ||||||||||||
| Oil (Bbl) | $ | 49.16 | $ | 41.51 | $ | 44.88 | ||||||
| Natural gas (Mcf) | 4.05 | 2.99 | 2.86 | |||||||||
| Total (BOE) | $ | 43.77 | $ | 36.04 | $ | 39.20 | ||||||
Average realized sales price (including impact of cash settled derivatives) | ||||||||||||
| Oil (Bbl) | $ | 47.78 | $ | 45.67 | $ | 56.82 | ||||||
| Natural gas (Mcf) | 4.10 | 3.00 | 3.26 | |||||||||
| Total (BOE) | $ | 42.76 | $ | 39.25 | $ | 49.18 | ||||||
| Operating costs per BOE | ||||||||||||
| Lease operating expense | $ | 5.96 | $ | 6.88 | $ | 7.71 | ||||||
| Production taxes | 2.67 | 2.13 | 2.79 | |||||||||
| Total | $ | 8.63 | $ | 9.01 | $ | 10.50 | ||||||
Major Customers
Our production is sold generally on month-to-month contracts at prevailing market prices. The following table identifiespresents customers to whom we sold a significant percentagethat represented 10% or more of our total oil and natural gas production, on an equivalent basis, during eachrevenues for at least one of the 12-month periods indicated: presented:
| 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 | |||||||||||||||||
| For the Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Plains Marketing, L.P. | 29 | % | 16 | % | 19 | % | |||
| Enterprise Crude Oil, LLC | 18 | % | 43 | % | 42 | % | |||
| Rio Energy International, Inc. | 17 | % | — | % | — | % | |||
| Shell Trading Company | 9 | % | 18 | % | 4 | % | |||
| Permian Transport and Trading | — | % | — | % | 15 | % | |||
| Other | 27 | % | 23 | % | 20 | % | |||
| Total | 100 | % | 100 | % | 100 | % | |||
* - Less than 10% for the respective years.
Because alternative purchasers of oil and natural gas are readily available, the Company believeswe believe that the loss of any of these purchasers would not result in a material adverse effect on itsour ability to marketsell future oil and natural gas production. We are not currently committedIn order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide a fixed and determinable quantity of oil or gas in the near future under our contracts.
financial security.
Leasehold Acreage
The following table shows our approximate developed and undeveloped (gross and net) leasehold acreage as of December 31, 2017.2021. 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 | 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 | |||||||||||||||||||||||||||||||||||||||||||||||
| Developed | Undeveloped | Total | ||||||||||||||||
| Gross | Net | Gross | Net | Gross | Net | |||||||||||||
Permian Basin (a) | 53,343 | 41,040 | 33,238 | 16,441 | 86,581 | 57,481 | ||||||||||||
| Other | 936 | 200 | 188 | 55 | 1,124 | 255 | ||||||||||||
| Total | 54,279 | 41,240 | 33,426 | 16,496 | 87,705 | 57,736 | ||||||||||||
(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 if necessary, is not considered material.
Undeveloped Acreage Expirations
The following table sets forth as of December 31, 20172021.keep our employees safe and healthy, engage employees with an inclusive
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.The expiring acreage set forthWe focus on the following in supporting our human capital:
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; andeasements, restrictions, rights-of-way and other matters that commonly affect property.
Seasonality of Business
Currently, the Company has general liability insurance coverage up to $1 million per occurrence and $2 million per policy in the aggregate, which includes sudden and accidental pollution liability coverage for the effects of pollution on third parties arising from its operations. The Company’s insurance policies contain high policy limits, and in most cases, deductibles (generally ranging from $0 to $250,000) that must be met prior to recovery. These insurance policies are subject to certain customary exclusions and limitations. The Company
maintains up to $100 million in excess liability coverage, which is in addition to and triggered if the underlying liability limits have been reached. In addition, the company purchases pollution legal liability coverage in the amount of $10 million, which is excess and difference in conditions of the liability coverage.
The Company requires its third-party contractors to signWe enter into master service agreements with our 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 third-party contractors that perform hydraulic fracturing operations for the Company sign master service agreements generally containing the indemnification provisions noted above. The Company does not currently have any insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations. However, the Company believes its general liability and excess liability insurance policies would cover foreseeable third party claims related to hydraulic fracturing operations and associated legal expenses, in accordance with, and subject to, the terms of such policies.
The Company re-evaluates We 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 we believe that we are properly insured based on the Company’sour risk analysis, it believes that it is properly insured, 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.
The Company’sOur headquarters are located in Natchez, Mississippi,Houston, Texas, in a building owned by the Company.with office space that we lease. We also maintain leasedown office buildings in Dilley and Pecos, Texas and lease and own offices in Houston andthe Midland, Texas.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
Callon had 169 employees as of December 31, 2017. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.
Operations conducted on federal or state oil and natural gas leases must comply with numerous regulatory restrictions, including various nondiscrimination statutes, royalty and related valuation requirements, and certain of these operations must be conducted pursuant to certain on-site security regulations and other appropriate permits issued by DOI Bureaus or other appropriate federal or state agencies.
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, the Federal Energy Regulatory Commission, or FERC, various state 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 Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.
Greenhouse Gas Regulation. More stringent laws and regulations relating tofederal level, although no comprehensive climate change legislation has been implemented to date, such legislation has periodically been introduced in the U.S. Congress and GHGs may be proposed or adopted in the futurefuture. 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 could cause us to incur material expenses in complying with them. natural gas we produce.
In addition to possible federal regulation, a number of states, individually and regionally, are also consideringother capital providers restricting or have implemented GHG regulatory programs. These potential regional and state initiatives may resulteliminating their investment in so-called “Cap-and-Trade programs”, under which overall
GHG emissions are limited and GHG emissions are then allocated and sold, and possibly other regulatory requirements, that could result in our incurring material expenses to comply, such as by being required to purchase or to surrender allowances for GHGs resulting from our operations. These federal, regional and local regulatory initiatives also could adversely affect the marketability of the 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
The EPA has 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 includes New Source Performance Standards for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds, or 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 seeks 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 oil wells newly constructed or refractured. The rules also establish specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. These rules require a number of modifications to our operations, including the installation of new equipment to control emissions from our wells. In 2015, the BLM finalized regulations for hydraulic fracturing activities on federal lands. Among other things, the BLM rules imposed new requirements to validate the protection of groundwater, disclosure of chemicals used in hydraulic fracturing and higher standards for the interim storage of recovered waste fluids from hydraulic fracturing. This rule was the subject of legal challenges. In late 2017, the BLM repealed the 2015 ruling; this repeal is the subject of further legal challenges. Similarly, in February 2018, BLM proposed a rule to review certain requirements in its rules regarding the control of methane.
RRC.
Mineral Leasing Act of 1920 (“Mineral Act”). The Mineral Act prohibits direct or indirect ownership of any interest in federal onshore oil and natural gas leases by a foreign citizen or a foreign corporation except through stock ownership in a corporation formed under the laws of the United States or of any U.S. state or territory, and only if the laws, customs, or regulations of their country of origin or domicile do not deny similar or like privileges to citizens or corporations of the United States. If these restrictions are violated, the oil and gas lease or leases can be canceled in a proceeding instituted by the United States Attorney General. Although the regulations of the BLM (which administers the Mineral Act) provide for agency designations of non-reciprocal countries, there are presently no such designations in effect. For any federal leasehold interest that the Company owns, it is possible that holders of the Company’s equity interests may be citizens of a foreign country, which is a non-reciprocal country under the Mineral Act. In such event, the federal onshore oil and gas leases held by the Company could be subject to cancellation based on such determination.
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; andnotice to, and consultation with, surface owners and other third parties.
and disgorgement of any ill-gotten gains.
related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at FERC and in the courts.
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 14 in“Note 17 - Commitments and Contingencies” of the FootnotesNotes to theour Consolidated Financial Statements for additional information.
ItemITEM 1A. Risk Factors
Risk Factors
the amount of oil and natural gas that we are economically able to produce;
AnyA substantial andor extended decline in commodity prices may also reduce the priceamount of oil orand 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 have an adverse effect on our borrowing capacity,also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to obtain additional capital,replace our production and our revenues, profitabilityfuture 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 cash flows.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 sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital expenditures may be materially and adversely affected.
For the period ended December 31, 2017, we did not recognize a write-downAn excess supply of oil and natural gas propertiesmay 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.
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.
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, including many that have significantly greater resources than us. Therefore, 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. Factors that affect our ability to compete in the marketplace include:
our access to the capital necessary to drill wells and acquire properties;our ability to acquire and analyze seismic, geological and other information relating to a property;our ability to retain the personnel necessary to properly evaluate seismic and other information relating to a property;our ability to procure materials, equipment, personnel and services required to explore, develop and operate our properties, including the ability to procure fracture stimulation services on wells drilled; andour ability to access pipelines, and the location of facilities used to produce and transport oil and natural gas production.
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. From time to time, our industry experiences a shortage of drilling rigs, equipment, supplies, water or qualified personnel. During these periods, the costs and delivery times of rigs, equipment and supplies are substantially greater. In addition, the demand for, and wage rates of, qualified drilling rig crews and other experienced personnel rise as the level of activity increases. Increasing levels of exploration and production may increase the demand for oilfield services and equipment, and the costs of these services and equipment may increase, while the quality of these services and equipment may suffer. The unavailability or high cost of drilling rigs, pressure pumping equipment, supplies, water or qualified personnel can materially and adversely affect our operations and profitability.
Our producing properties are located in the Permian Basin of West Texas, making us vulnerable to risks associated with operating in a single geographic area. In addition, we have a large amount of proved reserves attributable to a small number of producing horizons within this area. All of our producing properties are geographically concentrated in the Permian Basin of West Texas. As a result of this concentration, we may be disproportionately exposed to the impact of regional supply and demand factors, delays or interruptions of production from wells in this area caused by governmental regulation, processing or transportation capacity constraints, availability of equipment, facilities, personnel or services market limitations or interruption of the processing or transportation of oil, natural gas or natural gas liquids. In addition, the effect of fluctuations on supply and demand may become more pronounced within specific geographic oil and natural gas producing areas such as the Permian Basin, which may cause these conditions to occur with greater frequency or magnify the effects of these conditions. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties. Such delays or interruptions could have a material adverse effect on our financial condition and results of operations.
We maybe unable to integrate successfully the operations of recent and future acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. Our business has and may in the future include producing property acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our recent acquisitions or from any acquisitions we may complete in the future. In addition, failure to assimilate recent and future acquisitions successfully could adversely affect our financial condition and results of operations. Our acquisitions may involve numerous risks, including:
operating a larger combined organization and adding operations;difficulties in the assimilation of the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;risk that oil and natural gas reserves acquired may not be of the anticipated magnitude or may not be developed as anticipated;loss of significant key employees from the acquired business;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;diversion of management’s attention from other business concerns;failure to realize expected profitability or growth;failure to realize expected synergies and cost savings;coordinating geographically disparate organizations, systems and facilities; andcoordinating or consolidating corporate and administrative functions.
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. If we consummate any future acquisition, 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 subsequent acquisition and current operations, which in turn, could negatively impact our 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 of properties we acquire which 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 preclosing 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. 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 affect our ability to market production and our financial results. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. These factors could negatively affect our ability to market all of the oil or natural gas we produce. In addition, we may be unable to obtain favorable prices for the oil and natural gas we produce. These factors 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;the proximity of hydrocarbon production to pipelines;the availability of pipeline and/or refining capacity;the demand for oil and natural gas by utilities and other end users;the availability of alternative fuel sources;the effects of inclement weather;state and federal regulation of oil and natural gas marketing; andfederal regulation of natural gas sold or transported in interstate commerce.
In particular, in areas with increasing non-conventional shale drilling activity, pipeline, rail or other transportation capacity may be limited and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built.
The marketability ofour production is dependent upon transportation facilities and services owned and operated by third parties, and the unavailability of these facilities or services would have a material adverse effect on our revenue. Our ability to market our production depends on the availability and capacity of 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 or other reasons. In addition, in certain newer development areas, transportation facilities and services may not be sufficient to accommodate potential production. Our failure to obtain access to 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 transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until production 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.
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, wells that are profitable may not achieve our targeted rate of return.
In addition, we may not be successful in controlling our drilling and production costs to improve our overall return. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including among others:
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; andcompliance with governmental requirements.
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.
drilling results;gathering, marketingexpirations, regulatory approvals, and transportation constraints; and
regulatory approvals.
Risks Related to TechnologyThe 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, including Howard and Ward Counties, are generally more uncertain than drilling results in areas that are less developed and have more established production from horizontal formations such as the Wolfcamp, Spraberry and Bone Spring horizons. 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, 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 are less than anticipated or we are unable to execute our drilling program because of capital constraints, access to gathering systems and takeaway capacity or otherwise, and/or natural gas and oil prices decline, our investment in these areasWe may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value ofable to keep pace with technological developments in our undeveloped acreage could decline in the future.
Unexpected subsurface conditions and other unforeseen operating hazards may adversely impact our ability to conduct business. There are many operating hazards in exploring for and producingindustry. The oil and natural gas including: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 drilling operations may encounter unexpected formationsOur business could be negatively affected by security threats. A cyberattack or pressures, whichsimilar incident could causeoccur and result in information theft, data corruption, operational disruption, damage to equipmentour reputation or personal injury;we may experience equipment failures which curtail or stop production;we could experience blowouts or other damages to the productive formations that may require a well to be re-drilled or other corrective action to be taken; andstorms and other extreme weather conditions could cause damages to our production facilities or wells.
Because of these or other events, we could experience environmental hazards, including release offinancial loss. The 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, it could affect well bores, gathering systems and processing facilities, which could adversely affect our ability to conduct operations. We could also incur substantial losses in excess of our insurance coverage as a result of:
injury or loss of life;severe damage to and destruction of property, natural resources and equipment;pollution and other environmental damage;clean-up responsibilities;regulatory investigation and penalties;suspension of our operations; andrepairs to resume operations.
We cannot assure you that we will be able to maintain adequate insurance at rates we consider reasonable to cover our possible losses from operating hazards. The occurrence of a significant event not fully insured or indemnified against could materially and adversely affect our financial condition and results of operations.
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 our third party consultants, none of whom are 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.
Cyber-attacks targeting systems and infrastructure used by the oil and gas industry may adversely impact our operations. Our business 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. Unauthorized access to ourOur 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 data corruption, communication interruption,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 cyber-attackcyberattack 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 cyber securitycybersecurity threats. Our systems and
cyberattacks.
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:
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
Our leverage and debt service obligations may adversely affect our financial condition, results of operations, and business prospects. As of December 31, 2017, we had $600 million outstanding of 6.125% Senior Notes and $25 million outstanding under our Credit Facility, which had an additional $474 million available for borrowings based on the existing level of commitments. Our amount of indebtedness could affect our operations in several ways, including the following:
require us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;limit management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;increase our vulnerability to downturns and adverse developments in our business and the economy;limit 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;place restrictions on our ability to obtain additional financing, make investments, lease equipment, sell assets and engage in business combinations;make it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;make us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;place us at a competitive disadvantage relative to competitors with lower levels of indebtedness in relation to their overall size or less restrictive terms governing their indebtedness; andmake it more difficult for us to satisfy our obligations under the 6.125% Senior Notes or other debt and increase the risk that we may default on our debt obligations.
Risks Related to Our Hedging Program
We may not have production to offset hedges. Part of our business strategy is to reduce our exposure to the volatility of oil and natural gas prices by hedging a portion of our production. 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.
The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results. Our principal exposures to credit risk are through receivables resulting from the sale of our oil and natural gas production, which we market to energy marketing companies, refineries and affiliates, 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 29% of our total oil and natural gas revenues for the year ended December 31, 2017. We do not require any of our customers to post collateral. 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.
We have no plans to pay cash dividends on our common stock in the foreseeable future.The terms of our Credit Facility contain limitations that impact our ability to pay dividends and make other distributions. In addition, 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.
industry remains a possibility.
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 datedata gaps and uncertainties limited EPA’s assessment.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 make it difficultrestrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business.
Restrictions on emissions of methane or carbon dioxide that may be imposed could adversely impact theIn addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for price of,alternatives to oil and value of our productsnatural gas could reduce demand for oil and reserves. As our operations also emit greenhouse gases directly, current and future laws or regulations limiting such emissions could increase our own costs. At this time, it is not possible to accurately estimate how potential future laws or regulations addressing greenhouse gas emissions would impact our business.
In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves.natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere withimpact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims have been madeunder federal or state common law against certain energy companies alleging that GHG emissions frominvolved in the production of oil and natural gas operations constitute a public nuisance under federal and/or state common law.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, 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
While it is not possible at this time to predict when the CFTC will issue final rules applicable to position limits or capital requirements, dependingDepending 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, thesethe final rules and regulations 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, and may cause some entities to cease their current business as hedge providers.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).
Tax Risks
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 arewere 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
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
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.
reverse stock split.
Holders of our 10% Series A Cumulative Preferred Stock are entitled to a cumulative dividend whether or not declared, of $5.00 per annum, payable quarterly, equivalent to 10.0% of the liquidation preference of $50.00 per share. Unless the full amount of the dividends for the 10% Series A Cumulative Preferred Stock is paid in full, we cannot declare or pay any dividend on our common stock.
During 2017, neither the Company nor any affiliated purchasers made repurchases of Callon’s equity securities.
On February 4, 2016, a total of 120,000 shares of the Company’s 10% Series A Cumulative Preferred Stock were exchanged for 719,000 shares of common stock.
Equity Compensation Plan Information
The following table summarizes information regarding the number of shares of our common stock that are available for issuance under all of our existing equity compensation plans as of December 31, 2017 (securities amounts are presented in thousands).
For additional information regarding the Company’s benefit plans and share-based compensation expense, see Notes 8 and 9 in the Footnotes to the Financial Statements.
reflect the Company’s 1-for-10 reverse stock split effective August 7, 2020.
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, 2017 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 (dollars in thousands, except per share amounts).
General
Significant accomplishmentsfor2017include:
Increased annual production in 2017 by 50% to 8,373 MBOE as compared to 2016;Increased 2017 proved reserves by 50% to 137 MMBOE as compared to 2016;Entered the Delaware Basin through an acquisition completed in February 2017, acquiring approximately 29,175 gross (16,688 net) acres;In 2017, we transitioned from a two rig to a four rig horizontal drilling program.Issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes; andAmended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million, providing us with additional liquidity.
Operational Highlights
All of our producing properties are located in the Permian Basin. As a result of our acquisition and horizontal development efforts, our production grew 50% in 2017 compared to 2016, increasing to 8,373 MBOE from 5,573 MBOE. Our production in 2017 was approximately 78% oil and 22% natural gas.
In 2017, we transitioned from a two rig to four rig horizontal drilling program. For the year ended December 31, 2017, we drilled 49 gross (38.2 net) horizontal wells, completed 52 gross (41.4 net) horizontal wells and had four gross (2.0 net) horizontal wells awaiting completion.
Reserve Growth
As of December 31, 2017, our estimated net proved reserves increased 50% to 137.0 MMBOE compared to 91.6 MMBOE of estimated net proved reserves at year-end 2016. Our significant growth in proved reserves was primarily attributable to our horizontal development and acquisition efforts. Our proved reserves at year-end 2017 and 2016 were 78% oil and 22% natural gas for both periods.
Liquidity and Capital Resources
Historically, our primary sources of capital have been cash flows from operations, borrowings from financial institutions, the sale of debt and equity securities, and asset dispositions. Our primary uses of capital have been for the acquisition, development, exploration and exploitation of oil and natural gas properties, in addition to refinancing of debt instruments.
In 2017, we issued an additional $200 million aggregate principal amount of our 6.125% Senior Notes to raise additional capital. In addition, we amended the borrowing base under our Credit Facility to $700 million with a current elected commitment level of $500 million, providing us with additional liquidity. We continue to evaluate other sources of capital to complement our cash flow from operations and other sources of capital as we pursue our long-term growth plans. See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt.
For the year ended December 31, 2017, cash and cash equivalents decreased $625.0 million to $28.0 million compared to $653.0 million at December 31, 2016.
Liquidity and cash flow
Operating activities. For the year ended December 31, 2017, net cash provided by operating activities was $229.9 million, compared to $120.8 million for the same period in 2016. The change in operating activities was predominantly attributable to the following:
An increase in revenue;A decrease in settlements of derivative contracts;An increase in certain operating expenses related to acquired properties;An increase in payments in cash-settled restricted stock unit (“RSU”) awards; andA change related to the timing of working capital payments and receipts.
Production, realized prices, and operating expenses are discussed below in Results of Operations. See Notes 6 and 7 in the Footnotes to the Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation. See Note 3 in the Footnotes to the Financial Statements for more information on the Company’s acquisitions.
Investing activities. For the year ended December 31, 2017, net cash used in investing activities was $1,072.5 million compared to $866.3 million for the same period in 2016. The change in investing activities was primarily attributable to the following:
A $229.8 million increase in operational expenditures primarily due to our transition from a one-rig program in 2016 to a four-rig program in 2017. In August 2016, we transitioned from a one-rig program to a two-rig program. We transitioned from a two-rig program to a three-rig program in January 2017 and from a three-rig program to a four-rig program in July 2017; andA $23.6 million decrease in acquisitions, net of proceeds from the sale of mineral interest and equipment.Our investing activities, on a cash basis, include the following for the periods indicated (in thousands):
General and administrative expenses and capitalized interest are discussed below in Results of Operations. See Notes 3 and 14 in the Footnotes to the Financial Statements for additional information on significant acquisitions and drilling rig leases.
Financing 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, 2017, net cash provided by financing activities was $217.6 million compared to cash provided by financing activities of $1,397.3 million during the same period of 2016. The change in net cash provided by financing activities was primarily attributable to the following:
A decrease in proceeds resulting from common stock offerings. In 2016, we raised $1,357.6 million through four common stock offerings as compared no common stock offerings in 2017; andA $188.2 million decrease in borrowings on fixed rate debt. In 2016, we issued a $400 million aggregate principal amount of 6.125% Senior Notes, and in 2017, we issued an additional $200 million aggregate principal amount, including a premium issue price of 104.125%, of the 6.125% Senior Notes.
Net cash provided by financing activities includes the following for the periods indicated (in thousands):
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt. See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s equity offerings and Series A 10% Cumulative Preferred Stock.
Credit Facility
On May 31, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility with a maturity date of May 25, 2022. The total notional amount available under the Company’s Credit Facility is $2,000 million. Concurrent with the execution of the Sixth Amended and Restated Credit Agreement, the Credit Facility’s borrowing base increased to $650 million, but the Company elected an aggregate commitment amount of $500 million. On November 7, 2017, the Credit Facility’s borrowing base increased to $700 million with a reaffirmed commitment of $500 million, following the semi-annual review. As of December 31, 2017, the Credit Facility had a balance of $25 million outstanding.
For the year ended December 31, 2017, the Credit Facility had a weighted-average interest rate of 3.11%, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilization of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s Credit Facility.
6.125% Senior Notes
On October 3, 2016, the Company issued $400 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391.3 million. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.
On May 19, 2017, the Company issued an additional $200 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture.
The net proceeds of the offering, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $206.1 million.
See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
Holders of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for the payment of dividends, cumulative cash dividends at a rate of 10.0% per annum of the $50.00 liquidation preference per share (equivalent to $5.00 per annum per share). Dividends are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7.3 million in 2017.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the redemption date.
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
See Note 10 in the Footnotes to the Financial Statements for additional information about the Company’s Preferred Stock.
2018Capital Planand Outlook
Our operational capital budget for 2018 has been established in the range of $500 to $540 million on an accrual, or GAAP, basis, inclusive of a planned transition from a four rig program that commenced in July 2017 to a five rig program by mid-February 2018.
As part of our 2018 operated horizontal drilling program, we expect to place 43 to 46 net horizontal wells on production with lateral lengths ranging from 5,000’ to 10,000’.
In addition to the operational capital expenditures budget, which includes well costs, facilities and infrastructure capital, and surface land purchases, we budgeted an estimated $23 to $28 million for capitalized general and administrative expenses on an accrual, or GAAP, basis.
Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our reserves of oil and natural gas. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, including commodity hedging strategy, 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 Obligations
The following table includes the Company’s current contractual obligations and purchase commitments (in thousands):
(1) Reflects calendar average daily spot market prices.
Commodity Prices
The prices for oil and natural gas 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(1) Excludes sales of oil and natural gas will affect the following aspects ofpurchased from third parties and sold to our business:customers.
our revenues, cash flows and earnings;the amount of oil and natural gas that we are economically able to produce;our ability to attract capital to finance our operations and cost of the capital;the amount we are allowed to borrow under our Credit Facility; andthe value of our oil and natural gas properties.
For the year ended December 31, 2017, the average NYMEX price for a barrel of oil was $50.80 per Bbl compared to $43.39 per Bbl for the same period of 2016. The NYMEX price for a barrel of oil ranged from a low of $42.53 per Bbl to a high of $60.42 per BblRevenues for the year ended December 31, 2017.
For the year ended December 31, 2017, the average NYMEX price for natural gas was $3.02 per MMBtu compared to $2.55 per MMBtu for the same period in 2016. The NYMEX price for natural gas ranged from a low2021, of $2.56 per MMBtu to a high of $3.42 per MMBtu for the year ended December 31, 2017.
Oil revenue
For the year ended December 31, 2017, oil revenues of $322 million$1.9 billion increased $145$867.8 million, or 81%88%, compared to revenues of $178$983.8 million for the year ended December 31, 2016.2020. The increase in oil revenue was primarily attributable to a 53% increase in production and an 18%101% increase in the average realized sales price which rose to $49.16$53.06 per BblBoe from $41.51$26.45 per Bbl.Boe as well as revenue attributable to wells that were acquired in the Primexx Acquisition. The increase in the average realized sales price was partially offset by a 6% decrease in production, which was comprisedprimarily due to the divestitures that occurred during 2021 as well as normal production decline, partially offset by production resulting from our developmental activities during the year as well as production from the properties acquired in the Primexx Acquisition.
Natural gas revenue (including NGLs)
Natural gas revenues of $44.1 million increased $20.9 million, or 90%, during the year ended December 31, 2017 compared to $23.2 million for the year ended December 31, 2016. The increase primarily relates to a 40% increase in natural gas volumes and a 35% increase in the average price realized, which rose to $4.05 per Mcf from $2.99 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,969 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,375 MMcf attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Natural gas revenues of $23.2 million increased $10.9 million, or 88%, during the year ended December 31, 2016 compared to $12.3 million for the same period of 2015. The increase primarily relates to an 80% increase in natural gas volumes and a 5% increase in the average price realized, which rose to $2.99 per Mcf from $2.86 per Mcf, reflecting increases in both natural gas and natural gas liquids prices. The increase in production was comprised of 1,387 MMcf attributable to wells placed on production as a result of our horizontal drilling program and 1,025 MMcf attributable to producing wells added from our acquired properties. In addition, the increase in production taxes described above was also attributable to the increase in the percentage of natural gas produced in our production stream.
Operating Expenses
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Lease 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.
LOE for the year ended December 31, 2017 increased by 30% to $49.9 million compared to $38.4 million for the same period of 2016. Contributing to the increase was $11.0 million related to oil and natural gas properties acquired during 2016 and 2017 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). LOE per BOE for the year ended December 31, 2017 decreased to $5.96 per BOE compared to $6.88 per BOE for the same period of 2016, which was primarily attributable to higher production volumes resulting from an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.
LOE for the year ended December 31, 2016 increased by 42% to $38.4 million compared to $27.0 million for the same period of 2015. Contributing to the increase for the current period was $7.3 million related to oil and natural gas properties acquired during 2016 (see Note 3 in the Footnotes to the Financial Statements for information about the Company’s acquisitions). Excluding LOE related to these acquired properties, LOE increased by $4.0 million, or 15%, compared to the same period of 2015. LOE per BOE for the year ended December 31, 2016 decreased to $6.88 per BOE compared to $7.71 per BOE for the same period of 2015, which was primarily attributable to higher production volumes offset by an increase in cost from workover activity on our legacy properties. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions as discussed above.
Production taxes. Production taxes include severance and ad valorem taxes. In general, production taxes are directly related to commodity price changes; however, severance taxes are based upon current year commodity prices, whereas ad valorem taxes are based upon prior year commodity prices. Severance taxes are paid on produced oil and natural gas based on a percentage of revenues from products sold at fixed rates established by federal, state or local taxing authorities. Where available, we benefit from tax credits and exemptions in our various taxing jurisdictions. In the counties where our production is located, we are also subject to ad valorem taxes, which are generally based on the taxing jurisdictions’ valuation of our oil and gas properties.
For the year ended December 31, 2017, production taxes increased 89%, or $10.5 million, to $22.4 million compared to $11.9 million for the same period of 2016. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase was also attributable to an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by
the taxing jurisdictions due to an increased number of producing wells as a result of our horizontal drilling program and acquisitions. On a per BOE basis, production taxes for the year ended December 31, 2017 increased by 25% compared to the same period of 2016.
For the year ended December 31, 2016, production taxes increased 21%, or $2.1 million, to $11.9 million compared to $9.8 million for the same period of 2015. The increase was primarily due to an increase in severance taxes, which was attributable to the increase in revenue. The increase waspartially offset by a decrease in ad valorem taxes attributabledue to lower property tax valuations for 2021 as a result of lower valuationcommodity prices during 2020. Production and ad valorem taxes as a percentage of our oil and gas properties by the taxing jurisdictions. On a per BOE basis, production taxestotal revenues decreased to 5.4% for the year ended December 31, 2016 decreased by 24%2021, as compared to 6.4% of total revenues for the same period of 2015.2020, primarily due to lower property tax valuations for 2021 as discussed above.
Depreciation, depletionGathering, Transportation and amortization (“DD&A”). Under the full cost accounting method, we capitalizeProcessing Expenses. Gathering, transportation and processing costs within a cost center and then systematically expense those costs on a units-of-production basis based on proved oil and natural gas reserve quantities. We calculate depletion on the following types of costs: (i) all capitalized costs, other than the cost of investments in unevaluated properties, less accumulated amortization; (ii) the estimated future expenditures to be incurred in developing proved reserves; and (iii) the estimated dismantlement and abandonment costs, net of estimated salvage values. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to fifteen years.
Forfor the year ended December 31, 2017, DD&A2021 increased 62%by 5% to $115.7 million from $71.4$81.0 million compared to the same period of 2016. The increase is primarily attributable to a 50% increase in production and an 8% increase in our per BOE DD&A rate.The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2017, DD&A on a per unit basis increased to $13.82 per BOE compared to $12.81 per BOE$77.3 million for the same period of 2016. The increase is attributable to our increase in our depreciable base and assumed future development costs2020, which was primarily related to undeveloped proved reserves relativenew 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 volumes between the two periods as discussed above.
G&AImpairment of Evaluated Oil and Gas Properties. We did not recognize an impairment of evaluated oil and gas properties for the year ended December 31, 2016 decreased to $26.3 million compared to $28.3 million for the same period2021. Impairments of 2015. G&A expenses for the periods indicated include the following (in thousands):
Settled share-based awards. In June 2017, the Company settled the outstanding share-based award agreementsevaluated oil and gas properties of its former Chief Executive Officer, resulting in $6.4 million recorded on the Consolidated Statements of Operations as Settled share-based awards.
Accretion expense. The Company is required to record the estimated fair value of liabilities for obligations associated with the retirement of tangible long-lived assets and the associated ARO costs. Interest is accreted on the present value of the ARO and reported as accretion expense within operating expenses in the Consolidated Statements of Operations.
Accretion expense related to our ARO decreased 29%$2.5 billion were recognized for the year ended December 31, 20172020, 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.
Accretion expense related to our ARO increased 45% forPrimexx Acquisition and the year ended December 31, 2016 compared to the same period of 2015. Accretion expense generally correlates with the Company’s ARO, which was $6.7 million at December 31, 2016 versus $5.1 million at December 31, 2015. See Note 12 in the Footnotes to the Financial Statements for additional information regarding the Company’s ARO.
Write-down of oil and natural gas properties. Under full cost accounting rules, the Company reviews the carrying value of its proved oil and natural gas properties each quarter. Under these rules, capitalized costs of oil and natural gas properties, net of accumulated depreciation, depletion and amortization and deferred income taxes, may not exceed the present value of estimated future net cash flows from proved oil and natural gas reserves, discounted at 10%, plus the lower of cost or fair value of unevaluated properties, net of related tax effects (the full cost ceiling amount). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling.
For the year ended December 31, 2017, the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the year ended December 31, 2016, the Company recognized a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation, primarily driven by a 15% decrease in the 12-month average realized price of oil from $50.16 per barrel as of December 31, 2015 to $42.75 per barrel as of December 31, 2016. If commodity prices were to decline, we could incur additional ceiling test write-downs in the future. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information.
Rig termination fee. For the year ended December 31, 2015, the Company recognized $3.1 million in expense related to the early termination of the contract for its vertical rig. See Note 14 in the Footnotes to the Financial Statements for additional information.
Acquisition expense. Acquisition expense decreased $0.8 million for the year ended December 31, 2017 compared to the same period of 2016 and increased $3.6 million for the year ended December 31, 2016 compared to the same period of 2015. Acquisition expense for all periods was related to costs with respect to our acquisition efforts in the Permian Basin. See Note 2 in the Footnotes to the Financial Statements for additional information regarding the Company’s acquisitions.
Carrizo Acquisition.
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Interest expense, net of capitalized amounts incurred during the year ended December 31, 2017 decreased $9.7 million to $2.2 million compared to $11.9 million for the same period of 2016. The decrease is primarily attributable to a $13.9 million increase in capitalized interest compared to the 2016 period, resulting from a higher average unevaluated property balance for the year ended December 31, 2017 as compared to the same period of 2016. The increase in unevaluated property was primarily due to acquired properties(see Note 3 and 13 in the Footnotes to the Financial Statements for information about the Company’s acquisitions and unevaluated property balance).Offsetting the decrease was a $5.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2017 as compared to the same period of 2016, resulting from the issuance of an additional $200 million of our 6.125% Senior Notes in May 2017 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes).periods indicated:
Gain (loss)on the early extinguishment of debt. During October 2016, the secured second lien term loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12.9 million (inclusive of $3.0 million in prepayment fees and $9.9 million of unamortized debt issuance costs). See Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s debt.
Gain(loss)on derivative instruments. 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 positions2020, we have concluded that have settled within the period.
For the year ended December 31, 2017, the net loss on derivative instruments was $18.9 million, compared to a $20.2 million net loss in 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
For the year ended December 31, 2016, the net loss on derivative instruments was $20.2 million, compared to a $28.4 million net gain in 2016. The net gain (loss) on derivative instruments for the periods indicated includes the following (in thousands):
See Notes 6 and 7 in the Footnotes to the Financial Statements for additional information on the Company’s derivative contracts and disclosures related to derivative instruments.
Income tax expense.We use the asset and liability method of accounting for income taxes, under which deferred tax assets and liabilities are recognized for the future tax consequences of (1) temporary differences between the financial statement carrying amounts and 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 effect of a change in tax rates 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 net deferred tax assets will not be realized.realized and have recorded a full valuation allowance against our deferred tax assets, which still remained as of December 31, 2021. See “Note 12 – Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding the valuation allowance.
•A decrease in capital expenditures.The Company had an income tax benefit of less than $0.1 million forFinancing Activities. For the year ended December 31, 20162021, net cash used in financing activities was $108.1 million compared to an income tax expense$23.0 million during 2020. The increase in net cash used in financing activities was primarily attributable to the following:
We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations.
The following table presents a reconciliation(1)For each of the federal statutory tax ratescommitments 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 effective tax rates:purchases of third-party commodities.
Critical Accounting Estimates
Preferred stock dividends. Holders of our Preferred Stock are entitled to receive, when, as and if declared by our Board 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).
Preferred stock dividends for the year ended December 31, 2017 were consistent with the same period of2016. Preferred stock dividends for the year ended December 31, 2016 decreased $0.6 million compared to the same period of 2015. The decrease was due to a decrease in the number of preferred shares outstanding, attributable to a partial share conversion in February 2016 in which the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. Dividends reflect a 10% dividend yield. See Note 10 in the Footnotes to the Financial Statements for additional information.
The discussion and analysis of our financial condition and results of operations are based upon our consolidated financial statements, which have been prepared in accordance with GAAP. The preparation of our consolidated financial statements in conformity with GAAP requires usmanagement to make judgments affecting estimates and assumptions that affect ourfor reported resultsamounts of operationsassets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the amountreported amounts of reported assets, liabilitiesrevenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of evaluated oil and natural gas reserves. Some accounting policies involve judgments and uncertainties to such an extent that there is reasonable likelihood that materially different amounts could have been reported under different conditions, or if different assumptions had been used. Actual results may differ from the estimates and assumptions used in the preparation of our consolidated financial statements. Described below are the most significant policies we apply in preparing our consolidated financial statements, some of which are subject to alternative treatments under GAAP. We also describe the most significant estimates and assumptions we make in applying these policies. See Note 2 in the Footnotes to the Financial Statements included elsewhere in this Annual Report on Form 10-K for a discussion of additional accounting policies and estimates made by management.
Oil and natural gas properties
The Company utilizes the full cost method of accounting for its oil and natural gas properties whereby all costs incurred in connection with the acquisition, exploration and development of oil and natural gas reserves, including certain overhead costs, are capitalized into the “full cost pool.” The amounts capitalized into the full cost pool are depleted (charged against earnings) using the unit-of-production method. The full cost method of accounting for oil and natural gas properties requires that the Company makes estimates based on its assumptions of future events that could change. These estimates are described below.
Depreciation,depletion and amortization (DD&A) of oil and natural gas properties
The Company calculates DD&A by using the depletable base, which is equal to the net capitalized costs in our full cost pool plus estimated future development costs, and the estimated net proved reserve quantities. Capitalized costs added to the full cost pool include the following:costs of drilling and equipping productive wells, dry hole costs, acquisition costs of properties with proved reserves, delay rentals and other costs related to exploration and development of our oil and natural gas properties;payroll costs including the related fringe benefits paid to employees directly engaged in the acquisition, exploration and/or development of oil and natural gas properties as well as other directly identifiable general and administrative costs associated with such activities. Such capitalized costs do not include any costs related to the production of oil and natural gas or general corporate overhead;costs associated with unevaluated properties, those lacking proved reserves, are excluded from the depletable base. These unevaluated property costs, are added to the depletable base at such time as wells are completed on the properties or management determines these costs have been impaired. The Company’s determination that a property has or has not been impaired (which is discussed below) requires assumptions about future events;estimated costs to dismantle, abandon and restore properties that are capitalized to the full cost pool when the related liabilities are incurred (see also the discussion below regarding Asset Retirement Obligations);estimated future costs to develop proved properties are added to the full cost pool for purposes of the DD&A computation. The Company uses assumptions based on the latest geologic, engineering, regulatory and cost data available to it to estimate these amounts. However, the estimates made are subjective and may change over time. The Company’s estimates of future development costs are reviewed at least annually and as additional information becomes available; andcapitalized costs included in the full cost pool plus estimated future development costs are depleted and charged against earnings using the unit-of-production method. Under this method, the Company estimates the proved reserves quantities at the beginning of each accounting period. For each BOE produced during the period, the Company records a DD&A charge equal to the amount included in the depletable base (net of accumulated depreciation, depletion and amortization) divided by our estimated net proved reserve quantities.Because the Company uses estimates and assumptions to determine proved reserves (as discussed below) and the amounts included in the depletable base, our depletion rates may materially change if actual results differ from these estimates.
Ceilingtest
Under the full cost method of accounting, the Company compares, at the end of each financial reporting period, the present value of estimated future net cash flows from proved reserves (excluding cash flows related to estimated abandonment costsrevenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the valueestimated 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
proved reserves plus the lower of cost or fair value of unevaluated properties, the Company is required to write-down the value of its oil and natural gas properties to the value of the discounted cash flows. Estimated future net cash flows from proved reserves are based on a twelve-month average pricing assumption. Given the volatility of oil and natural gas prices, it is reasonably possible that the Company’s estimates of discounted future net cash flows from proved oil and natural gas reserves could changesummarized in the near term. For the periods ended December 31, 2017, the Company recognized no write-down of oil and natural gas properties as a result of the ceiling test limitation. For the periods ending December 31, 2016 and 2015 the Company recognized write-downs of oil and natural gas properties of $95.8 million and $208.4 million, respectively, as a result of the ceiling test limitation. If oil and natural gas prices were to decline, even if only for a short period of time, we could incur additional write-downs of oil and natural gas properties in the future. See Notes 2 and 13 in the Footnotes to the Financial Statements for additional information regarding the Company’s oil and natural gas properties.table below:
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 oil and natural gas production in the future. Oil and natural gas prices are volatile, but we are required to assume that they remain constant, using the twelve-month average pricing assumption. In general, higher oil and natural gas prices will increase quantities of proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; andthe 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 oil and natural gas quantities 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 quantities of oil and natural gas reserves for the Company’s properties that have relatively short productive lives. If oil and natural gas 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 oil and natural gas reserves.
In addition, the process of estimating proved oil and natural gas reserves requires that the Company’sour 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 “RiskPart I, “Item 1A. Risk Factors.”
SalesThe table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2021 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, 2021 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, are accounted for as adjustments to the net full cost pool with no gain or loss recognized unless the adjustment would significantly alter the relationship between capitalized costs and proved reserves.
Unprovedproperties
Costs, including capitalized interest, associated with properties that do not have proved reserves are excluded from the depletable base, and are includedproduction, changes in the line item “Unevaluated properties.” Unevaluated property costs are transferred to the depletable base when wells are completed on the properties or management determines that these costs have been impaired. In addition, the Company is required to determine whether its unevaluated properties are impaired and, if so, include the costs of such properties in the depletable base. We assess properties on an individual basis or as a group. The Company considers the following factors, among others: exploration program and intent to drill, remaining lease term, and the assignment of proved reserves. This determination may require the exercise of substantial judgment by management.
Assetretirementobligations
We are required to record our estimate of the fair value of liabilities for obligations associated with the retirement of tangible long-life assets and the associated asset retirement costs. We estimate the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjusted discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on the present value of the asset retirement obligations and reported as accretion expense within operating expenses 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.Estimating the future plugging and abandonment costs of wells and related facilities is difficult and 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.See Note 12 in the Footnotes to the Financial Statements for additional information.
Derivatives
To managecrude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2021 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 may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.”
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 6to our Consolidated Financial Statements.
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.
Taxes
Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income 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.
Pronouncements
Off-balance Sheet Arrangements
We had no off-balance sheet arrangements as of December 31, 2017.
ItemITEM 7A. Quantitative and Qualitative Disclosures about Market Risk
Commodity Price RiskCommodity price 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.
The Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 5,842 MBbls and 4,086 MMBtu of our expected oil and natural gas production, respectively, for the full year of 2018. We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 5,289 MBbls of our expected oil production for the full year of 2018. See Note 6 in the Footnotes to the Financial Statements for a description of the Company’s outstanding derivative contracts at December 31, 2017, and derivative contracts established subsequent to that date.
The Company 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 isWe are subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2017, the Company2021, we had $25.0$785.0 million outstanding under the Credit Facility with a weighted average interest rate of 3.11%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 $0.3$7.9 million, based on the balance outstanding atas of December 31, 2017.2021. See Note 5 in“Note 7 - Borrowings” of the FootnotesNotes to theour Consolidated Financial Statements for more information on the Company’s interest rates on our Credit Facility.
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, 2017, three2021, four purchasers each accounted for more than 10% of our revenue: Plains Marketing, L.P. (29%); Enterprise Crude Oil, LLC (18%); and Rio Energy International, Inc. (17%). We do not require any of our customers to post collateral, and therevenue. The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. At December 31, 2017In order to mitigate potential exposure to credit risk, we may require from time to time for our total receivables fromcustomers to provide financial security. We are generally paid by our purchasers within 30 to 90 days after the salemonth of our oilproduction and natural gas production were approximately $70.1 million.
currently do not believe that we have a risk of not collecting.
At December 31, 2017See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our receivables resulting from derivative contracts were approximately $1.9 million. Our oil and natural gas derivative arrangements expose us toConsolidated Financial Statements for discussion of counterparty credit risk in the event of nonperformance by counterparties. Most of the counterparties on our derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional 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 derivative, whereby the party not in default may offset all derivative liabilities owed to the defaulting party against all derivative asset receivables from the defaulting party. At December 31, 2017 we had a net derivative liability position of $28.6 million.arrangements.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm
Critical audit matters
The 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.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRMReport of Independent Registered Public Accounting Firm
The Board of Directors and Stockholders ofShareholders
Definition and limitations of internal control over financial reportingIn our opinion,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 referred to above present fairly,for external purposes in all material respects, the consolidated results of operations and cash flows of Callon Petroleum Company for the year ended December 31, 2015, in conformityaccordance with U.S. 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.
New Orleans, LouisianaHouston, TexasMarch 2, 2016February 24, 2022
Part 1. Financial InformationItem I. Financial Information
Description of business
Callon isThe Company’s activities are primarily focused on horizontal development in the acquisition, development, explorationMidland and exploitationDelaware Basins, both of unconventional onshore, oil and natural gas reserveswhich are part of the larger Permian Basin in West Texas, as well as the Eagle Ford in South Texas. The Company’s primary operations in the Permian Basin. The Company’s operations to date have been predominantly focused on thereflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable cash flow-generating business in the Eagle Ford.
Significant Accounting Policies
Unless otherwise indicated, all dollar amounts included within theFootnotes to theFinancial Statements are presented in thousands, except for per sharePresentation and per unit data.
Principles of Consolidation
Note 2– Summaryof Significant Accounting Policies
Accounts receivable consists primarily of accrued oil and natural gas production receivables and joint interest receivables from outside working interest owners.
Concentration of Credit Risk and Major Customers
See the Accounting Standards Updates (“ASU”) section within this footnote for information about recently issued ASUs related to Revenue Recognition.
The Company’s production is generally sold on month-to-month contracts at prevailing prices. The following table identifies customers to whom it sold greater than 10% of its total oil and natural gas production during each of the years ended:
Because alternative purchasers of oil and natural gas are readily available, the Company believes thatdoes not believe the loss of any one of theseits purchasers would not result in a material adverse effect onmaterially affect its ability to market futuresell the oil and natural gas production.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:
(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2021.
the United States and currently all revenues are attributable to customers located in the United States.Throughout 2015 and 2016, the FASB issued several updates2020, 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 revenue recognition guidance in Topic 606.Company’s consolidated financial statements or disclosures.
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.
ASU No. 2016-12, Revenue from Contracts with Customers - Narrow-Scope Improvements and Practical Expedients. This update applies only to the following areas from Accounting Standards Codification Topic 606: assessing the collectability criterion and accounting for contracts that do not meet the criteria for step 1, presentation of sales taxes and other similar taxes collected from customers, non-cash consideration, contract modification at transition, completed contracts at transition and technical correction. These updates will be effective for annual and interim reporting periods beginning after December 15, 2017.The Company adopted the new standard on January 1, 2018 using the modified retrospective method at the date of adoption. The Company does not expect the adoption of this standard will have a material impact on our Consolidated Financial Statements. The Company has determined that under certain natural gas processing agreements where control of the natural gas changes at the wellhead or inlet of the processing entity’s system, the treatment of gathering and treating fees should be recorded net of revenue in accordance with the new guidance. Gathering and treating fees have historically been recorded as an expense in lease operating expenses in our Statement of Operations. Beginning on January 1, 2018, the Company anticipates to modify our presentation of revenues and expenses to include these fees net of revenue.
Recently Issued ASUs - Other
In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842) (“ASU 2016-02”). The standard requires all lease transactions (with terms in excess of 12 months) to be recognized on the balance sheet as lease assets and lease liabilities. Public entities are required to apply ASU 2016-02 for annual and interim reporting periods beginning after December 15, 2018 with early adoption permitted. The Company is currently evaluating the impact of its pending adoption of this guidance on its consolidated financial statements.
In August 2016, the FASB issued ASU No. 2016-15, Statement of Cash Flows (Topic 230): Classification of Certain Cash Receipts and Cash Payments (“ASU 2016-15”). The objective of the standard is to reduce the existing diversity in practice of several cash flow issues, including debt prepayment or debt extinguishment costs, settlement of zero-coupon debt instruments or other debt instruments with coupon rates that are insignificant in relation to the effective interest rate of the borrowing, contingent consideration payment made after a business combination, proceeds from the settlement of insurance claims, proceeds from the settlement of corporate-owned life insurance policies, including bank-owned life insurance policies, distributions received from equity method investees, beneficial interests in securitization transactions, and separately identifiable cash flows and application of the predominance principle. The guidance in ASU 2016-15 is effective for public entities for annual reporting periods beginning after December 15, 2017, including interim periods therein. Early adoption is permitted and is to be applied on retrospective basis. The Company is currently evaluating the method of adoption and impact this standard may have on its consolidated financial statements and related disclosures.
In January 2017, the FASB issued ASU No. 2017-01, Business Combinations-Clarifying the Definition of a Business (“ASU 2017-01”). The guidance in ASU 2017-01 clarifies the definition of a business with the objective of adding guidance to assist entities with evaluating whether transactions should be accounted for as acquisitions or disposals of assets or businesses. The guidance provides a screen to determine when a set is not a business. The screen requires that when substantially all of the fair value of the gross assets acquired or disposed of is concentrated in a single identifiable asset or a group of similar identifiable assets, the set is not a business. The guidance in ASU 2017-01 is effective for annual reporting periods beginning after December 15, 2017, including interim periods therein. The Company will adopt this update prospectively effective January 1, 2018. The adoption of this update will not have an impact on its consolidated financial statements
Recently Adopted ASUs
In March 2016, the FASB issued ASU No. 2016-09, Compensation - Stock Compensation (Topic 718): Improvements to Employee Share-Based Payment Accounting (“ASU 2016-09”). The standard is intended to simplify several aspects of the accounting for share-based payment transactions, including the income tax consequences, classification of awards as either equity or liabilities, and classification on the statement of cash flows, and will allow companies to estimate the number of stock awards expected to vest. The guidance in ASU 2016-09 is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods therein. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements. The Company has elected to no longer estimate forfeitures.
In December 2016, the FASB issued ASU No. 2016-18, Statement of Cash Flows (Topics 230): Restricted Cash (“ASU 2016-18”). The objective of the standard is to require the change during the period in total restricted cash and cash equivalents to be included with cash and cash equivalents when reconciling the beginning-of-period and the end-of-period total amounts shown on the statement of cash flows. The Company adopted this ASU on January 1, 2017 and it did not have a material impact on its financial statements.
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.Note 3 – AcquisitionsPro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2021 and Dispositions
Acquisitions were accounted for under2020 was derived from the acquisition method of accounting, which involves determining the fair valuehistorical financial statements of the assets acquired and liabilities assumed underCompany giving effect to the income approach.
2017 Acquisitions
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,Primexx Acquisition, as if it had occurred on January 1, 2020. The below information reflects pro forma adjustments for total cash consideration of $646,559, excluding customary purchase price adjustments (the “Ameredev Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Transaction. In December 2016, in connection with the execution of the purchase and sale agreement for the Ameredev Transaction, the Company paid a deposit in the amount of $46,138 to a third party escrow agent, which was recorded as Acquisition deposit on the balance sheet as of December 31, 2016. The following table summarizes the estimated acquisition date fair values of the acquisition:
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 Transaction discussed above, for total cash consideration of $52,500, excluding customary purchase price adjustments. The Company funded the cash purchase price with its available cash and proceeds from the issuance of an additional $200,000 of its 6.125% senior notes due 2024 (“6.125% Senior Notes”) (see Note 5 for additional information regarding the Company’s debt obligations).
2016 Acquisitions
On October 20, 2016, the Company completed the acquisition of 6,904 gross (5,952 net) acres primarily located in Howard County, Texas from Plymouth Petroleum, LLC and additional sellers that exercised their “tag-along” sales rights, for total cash consideration of $339,687, excluding customary purchase price adjustments (the “Plymouth Transaction”). The Company funded the cash purchase price with the net proceeds of an equity offering (see Note 10 for additional information regarding the equity offering). The Company acquired an 82% average working interest (62% average net revenue interest) in the properties acquired in the Plymouth Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
On May 26, 2016, the Company completed the acquisition of 17,298 gross (14,089 net) acres primarily located in Howard County, Texas from BSM Energy LP, Crux Energy LP and Zaniah Energy LP, for total cash consideration of $220,000 and 9,333,333 shares of common stock (at an assumed offering price of $11.74 per share, which isand the last reported sale price of our common stock onborrowings under the New York Stock Exchange on that date) for aCredit Facility as total purchase price of $329,573, excluding customary purchase price adjustments (the “Big Star Transaction”). The Company acquired an 81% average working interest (61% average net revenue interest) in the properties acquired in the Big Star Transaction. The following table summarizes the estimated acquisition date fair values of the net assets acquired in the acquisition:
During 2016, the Company also closed on various acquisitions in the Midland Basin for an aggregate total purchase price of approximately $73,240, net of $23,045 in sales of working interest. The acquisitions included the purchase of additional working interest and acreage in the Company’s existing core operating area.
2015 Acquisitions
During 2015, the Company closed on an acquisition in the Midland Basin for an aggregate total purchase price of approximately $29,800. The acquisition included the purchase of additional working interest in the Company’s existing core operating area.
Unauditedpro forma financial statements
The following unaudited summary pro forma financial information for the periods presented is for illustrative purposes only and does not purport to represent what the Company’s results of operations would have been if the Ameredev Transaction, Plymouth Transaction and Big Star Transaction had occurredconsideration, as presented, or to project the Company’s results of operations for any future periods:
The pro forma adjustments are based on available information and certain assumptions that managementthe Company believes provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Primexx Acquisition.
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.
(1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.
Senior(1) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving creditfacility (“of $18.1 million and $23.6 million as of December 31, 2021 and 2020, respectively, which are classified in “Deferred financing costs” in the consolidated balance sheets.
On May that, as of December 31, 2017, the Company entered into the Sixth Amended2021, had a maximum credit amount of $5.0 billion, a borrowing base and Restated Credit Agreement toelected 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 credit agreement governing the Credit Facility provides for interest-only payments until December 20, 2024 (subject to remaining springing maturity dates of (i) July 2, 2024 if the 6.125% Senior Notes due 2024 (the “6.125% Senior Notes”)
As of December 31, 2017, there was $25,000 outstandingfees at rates ranging between 0.375% to 0.500% on the Credit Facility. Forunused portion of lender commitments, which are included in “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
6.125%Senior Notes
On October 3, 2016, the Companycommon stock issued $400,000less aggregate principal amount of 6.125% SeniorSecond Lien Notes withexchanged, net of a maturity datepro-rata write-off of October 1, 2024associated unamortized discount of $16.9 million and interest payable semi-annually beginning on April 1, 2017. The net proceeds of the offering, after deducting initial purchasers’ discounts and estimated offering expenses, were approximately $391,270. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.fees incurred.
April 1, 2021.
Term loans
On March 11, 2014, the Company entered into a term loan in an aggregate amount of up to $125,000, including initial commitments of $100,000 and additional availability of $25,000 subject to the consent of two-thirdsEach of the lenders and compliance with financial covenants after giving effect to such increase. The term loan hadSenior Unsecured Notes described above are guaranteed on a maturity date of September 11, 2019, and was not subject to mandatory prepayments unless new debt or preferred stock was issued. It was prepayable atsenior unsecured basis by the Company’s option, subject to a prepayment premium.wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The prepayment amount was (i) 102% ifsubsidiary guarantor is 100% owned, all of the prepayment event occurred prior to March 11, 2015,guarantees are full and (ii) 101% ifunconditional and joint and several, the prepayment event occurred onparent company has no independent assets or after March 15, 2015 but before March 15, 2016,operations and (iii) 100% for prepayments made on or after March 15, 2016. any subsidiaries of the parent company other than the subsidiary guarantor are minor.
On October 8, 2014, the term loan described above was repaid in full using proceeds from a new secured second lien term loan (the “Second Lien Loan”) in conjunction with the closing of the Central Midland Acquisition, resulting in a loss on early extinguishment of debt of $3,054. The Second Lien Loan has a maturity date of October 8, 2021. The Royal Bank of Canada is Administrative Agent, and participants include several institutional lenders. Borrowings under the Second Lien Loan were subject to interest, calculated at a rate of LIBOR (subject to a floor rate of 1.0%) plus 7.5% per annum. The Company elected a LIBOR rate based on various tenors, and was incurring interest based on an underlying three-month LIBOR rate, which was last elected in July 2016. The Second Lien Loan was subject to a prepayment premium. The prepayment amount was (i) 102% of principal if the prepayment event occurred prior to October 8, 2016, and (ii) 101% of principal if the prepayment event occurred on or after October 8, 2016 but before October 8, 2017, and (iii) 100% of principal for prepayments made on or after October 8, 2017. The Second Lien Loan was secured by junior liens on properties mortgaged under the Credit Facility, subject to an intercreditor agreement.
On October 11, 2016, the Second Lien Loan was repaid in full at the prepayment rate of 101% using proceeds from the sale of the 6.125% Senior Notes, which resulted in a loss on early extinguishment of debt of $12,883 (inclusive of $3,000 in prepayment fees and $9,883 of unamortized debt issuance costs).
Restrictive covenants
The Company’s Credit Facility and the indenture governing our 6.125% Senior Notes contain variouscontains certain covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios.
The credit agreement governing the Credit Facility and the indentures governing the Company’s Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
Using Derivative Instruments
Offsetting
Contingent Consideration Arrangements
receipts are classified as cash flows
Financial statement presentation and settlements
Settlements of the Company’s derivative instruments are based on the difference between the contract price or prices specifiedfrom investing activities in the consolidated statements of cash flows. Each of these other contingent consideration arrangements acquired in the Carrizo Acquisition expired at the end of 2020.
Derivatives not designated as hedging instruments
Financial Statement Presentation and Settlements
As previously discussed, the Company’s derivative contracts are subject to master netting arrangements. The Company’s policy is to presentCompany presents the fair value of derivative contracts on a net basis in the consolidated balance sheet.sheet as they are subject to master netting arrangements. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:
For the periods indicated, the Company recorded the following related to its derivatives in the consolidated statement of operations as gain or loss on derivative contracts:
(1) Includes approximately $11.2 million of deferred premiums, which will be paid as the applicable contracts settle.
Positions
Subsequent Event
The following derivative contracts were executed after December 31, 2017 and before February 23, 2018:
TheAccounting guidelines for measuring fair value establish a three-level valuation hierarchy includedfor disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in GAAP gives the highest priority to measurement. The three levels are defined as follows:
liabilities.
Recurring Basis
The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the years ended December 31, 2021 and 2020.
Note 8 – Employee Benefit Plans
Savings and Protection Plan (“401(k) Plan”)
The 401(k) Plan provides employees with the option to defer receipt of a portion of their compensation, and the Company may, at its discretion, match a portion of the employee’s deferral with cash. The Company may also elect, at its discretion, to contribute a non-matching amount in cash and Company common stock to employees. The amounts held under the 401(k) Plan are invested in various funds maintained by a third party in accordance with the directions of each employee. An employee is fully vested, including Company discretionary contributions, immediately upon participation in the 401(k) Plan. The total amounts contributed by the Company, including the value of the common stock contributed, were $1,292, $1,018 and $999 in the years 2017, 2016 and 2015, respectively.
2011 Omnibus Incentive Plan (the “2011 Plan”)
The 2011 Plan, which became effective May 12, 2011 following shareholder approval, authorized and reserved for issuance 2,300,000 shares of common stock, which may be issued upon exercise of vested stock options and/or the vesting of any other share-based equity award that is granted under this plan. The 2011 Plan is the Company’s only active plan, and included a provision at inception whereby all remaining, un-issued and authorized shares from the Company’s previous share-based incentive plans became issuable under the 2011 Plan. This transfer provision resulted in the transfer of an additional 841,000 shares into the plan, increasing the quantity authorized and reserved for issuance under the 2011 Plan to 3,141,000 at the inception of the 2011 Plan. Another provision provided that shares, which would otherwise become available for issuance under the previous plans as a result of vesting and/or forfeiture of any equity awards existing as of May 12, 2012, would also increase the authorized shares available to the 2011 Plan.
At the 2015 Annual Meeting of Shareholders, the Company’s shareholders approved the First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan (the “First Amendment”), which provided for (i) an increase in the number of shares of the Company’s common stock available for grant under the Plan by 2,000,000 shares from 2,300,000 shares to 4,300,000 shares, (ii) the adoption of a “double trigger” meaning that, in the event of a Company change in control, early vesting or payment occurs only if a change in control occurs and the executive’s employment is terminated or constructively terminated, and (iii) the elimination of the adding back of terminated options and stock appreciation rights shares for future grants. The First Amendment was made effective as of May 14, 2015. Including the transfer provision mentioned above, the quantity authorized and reserved for issuance under the 2011 Plan is 5,141,000 as of the effective date of the First Amendment. As of December 31, 2017, the 2011 Plan had 1,338,356 shares remaining and eligible for future issuance.
RSU equityawards. RSU equity awards issued under the 2011 Plan may be subject to various vesting, accelerated vesting, and forfeiture provisions upon the occurrence of certain events. RSU equity awards under the 2011 Plan generally vest over time but may also be subject to attaining a specified performance metrics and may vest immediately or cliff vest at a specified date. The Company will recognize expense on the grant date for all immediately vesting awards, while it will recognize expense ratably over the requisite service (i.e. vesting) period for both cliff and ratably vesting awards.
For market-based RSU equity awards, the Company recognizes expense based onmeasures the fair value of asset retirement obligations as of the awards at the grant date. Awards withdate a market-based provision dowell begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not allow for the reversal of previously recognized expense, even ifobservable in the market metric is not achieved and no shares ultimately vest ortherefore are awarded. Market-based RSU equity awards that vest are based on a calculation that comparesdesignated as Level 3 within the Company’s total shareholder returnvaluation hierarchy. Significant inputs to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200% of the base units awarded.
Cash-settled RSUawards. Certain of the Company’s RSU awards require cash settlement. Cash-settled RSU awards are accounted for as liabilities as the Company is contractually obligated to settle these awards in cash. Changes in the fair value measurement of cash-settleable awards are recorded as adjustments to compensation expense.
A significant portionasset retirement obligations include estimates of the Company’s cash-settled RSU awards include a market-based vesting condition that determinescosts of plugging and abandoning oil and gas wells, removing production equipment and facilities, restoring the actual number of units that will ultimately vest. The number of RSUs that vest is based on a calculation that compares the Company’s total shareholder return to the same calculated return of a group of peer companies as selected by the Company, and the number of units that will vest can range between 0% and 200%surface of the base units awarded. The fair valueland as well as estimates of the Company’s market-based RSU awards is calculated using a Monte Carlo valuation model, which considers such inputs aseconomic lives of the Company’soil and its peer group’s stock prices, a risk-free interest rate,gas wells and an estimated volatilityfuture inflation rates. See “Note 14 - Asset Retirement Obligations” for the Company and its peer group.additional discussion.
2020 Omnibus Incentive PlanAs discussed in Note 8,Shares-based awards are granted under the Company grants various forms of share-based compensation awards to employees2020 Omnibus Incentive Plan (the “2020 Plan”), which replaced the 2018 Omnibus Incentive Plan (the “2018 Plan”). From the effective date of the Company and its subsidiaries and to non-employee members of2020 Plan, no further awards may be granted under the Board of Directors.2018 Plan, however, awards previously granted under the 2018 Plan will remain outstanding in accordance with their terms. At December 31, 2017,2021, there were 1,619,272 shares available for future share-based awards including stock options or restricted stock grants, under the 2020 Plan.
(1)Includes 3.2 thousand units associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors.
No Cash-Settled RSU Awards were granted to employees during the year ended December 31, 2021. Grant activity during the years ended December 31, 2020 and 2019 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period. The weighted average grant date fair value of Cash-Settled RSU Awards was $36.71, $26.84 and $105.08 for the years ended December 31, 2021, 2020 and 2019, respectively.
The following table presents the unrecognized compensation cost for the indicated periods:
The Company’s unrecognized compensation cost related to unvested RSU equity awards and cash-settleable RSU awards is expected to be recognized over a weighted-average period of two years.
The following table summarizes the Company’s liability for cash-settled RSU awards for the periods indicated:
Stock Options
The Company issued no stock options for the past three years and had no options vest or forfeit during 2017. Additionally, no options were exercised, and 15,000 options expired unexercised during the year. As of December 31, 2017, the Company had no options outstanding. As of December 31, 2016, the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 0.3 years. As of December 31, 2015, the Company had 15,000 options outstanding and exercisable at a weighted average exercise price per option of $14.37, with no aggregate intrinsic value and with a weighted-average remaining contract life per unit of 1.3 years.
Note 11– Stockholders’ EquityRestricted Stock UnitsSecond Lien Note Exchange
On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance
For the year ended December 31, 2016,September 2020 Warrants and November 2020 Warrants provided notice and exercised all outstanding warrants. As a result of the exercises, the Company granted 684,090 RSUs withissued a weighted average grant-date fair valuetotal of $12.63 per share. The fair value6.9 million shares of its common stock in exchange for 9.0 million outstanding warrants determined on a net shares vested during 2016 was $2,608. Forsettlement basis. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for additional details regarding the year ended December 31, 2015, the Company granted 559,556 RSUs with a weighted average grant-date fair value of $8.98 per share. The fair value of shares vested during 2015 was $5,425.
For the year ended December 31, 2017, 335,471 market-based cash-settled RSUs subject to the peer market-based vesting described in Note 8 vested at between 142% to 200% of their issued units, depending on the datereverse stock split of the vesting, resultingCompany’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. All share and per share amounts, except par value per share, in cash payments of $3,986the consolidated financial statements and notes in 2017 and payable amounts of $3,062 in 2018. Also during 2017, 43,031 non-market-based cash settled RSUs vested, resulting in cash payments of $526 in 2017. During 2016, 281,792 market-based cash-settled RSUs subjectthe 2020 Annual Report on Form 10-K were retroactively adjusted for all periods presented to the peer market-based vesting described above vested at 200% of their issued units, resulting in cash payments of $8,662 in 2017. Also during 2016, 45,282 non-market-based cash settled RSUs vested, resulting in cash payments of $493 in 2016. See Note 8 for additional information regarding cash-settleable RSUs.
Note 10– Equity Transactions
give effect to this reverse stock split.
HoldersOn July 18, 2019, all outstanding shares of Preferred Stock were redeemed at a total redemption price of $73.0 million. The Company recognized an $8.3 million loss on the redemption due to the excess of the Company’s Preferred Stock are entitled to receive, when, as and if declared by our Board of Directors, out of funds legally available for$73.0 million redemption price over 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 are payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by our Board of Directors. Preferred Stock dividends were $7,295, $7,295 and $7,895 in 2017, 2016 and 2015, respectively.
The Preferred Stock has no stated maturity and is not subject to any sinking fund or other mandatory redemption. On or after May 30, 2018, the Company may, at its option, redeem the Preferred Stock, in whole or in part, by paying $50.00 per share, plus any accrued and unpaid dividends to the$64.7 million redemption date.
Following a change of control in which the Company or the acquirer no longer have a class of common securities listed on a national exchange, the Company will have the option to redeem the Preferred Stock, in whole but not in part for $50.00 per share in cash, plus accrued and unpaid dividends (whether or not declared), to the redemption date. If the Company does not exercise its option to redeem the Preferred Stock upon such change of control, the holdersdate carrying value of the Preferred Stock have the option to convert the Preferred Stock intoStock.
Note 12 – Income Taxesa number of sharesThe components of the Company’s common stock based on the valueincome tax expense are as follows:
On February 4, 2016, the Company exchanged a total of 120,000 shares of Preferred Stock for 719,000 shares of common stock. As of December 31, 2017, the Company had 1,458,948 shares of its Preferred Stock issued and outstanding.
Common Stock
On December 19, 2016, the Company completed an underwritten public offering of 40,000,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634,934. Proceeds from the offering were used to substantially fund the Ameredev Transaction, described in Note 3.
On September 6, 2016, the Company completed an underwritten public offering of 29,900,000 shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $421,864. Proceeds from the offering were used to substantially fund the Plymouth Transaction, described in Note 3.
On May 26, 2016, the Company issued 9,333,333 shares of common stock to partially fund the Big Star Transaction, described in Note 3, at an assumed offering price of $11.74 per share, which is the last reported sale price of our common stock on the New York Stock Exchange on that date.
On April 25, 2016, the Company completed an underwritten public offering of 25,300,000 shares of its common stock for total net proceeds (after the underwriter’s discounts and commissions and estimated offering expenses) of approximately $205,869. Proceeds from the offering were used to fund the Big Star Transaction, described in Note 3, and other working interest acquisitions.
On March 9, 2016, the Company completed an underwritten public offering of 15,250,000 shares of its common stock for total net proceeds (after the underwriting discounts and estimated offering costs) of approximately $94,948. Proceeds from the offering were used to pay down the balance onvaluation allowance recorded against the Company’s Credit Facility andnet deferred tax assets. See “— Deferred Tax Asset Valuation Allowance” below for general corporate purposes.additional details.
On November 16, 2015, the Company completed an underwritten public offering of 12,000,000 shares of its common stock at $8.40 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,800,000 additional shares of common stock at $8.40 per share, before underwriting discounts. The Company received net proceeds of approximately $109,864, after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility.
On March 13, 2015, the Company completed an underwritten public offering of 9,000,000 shares of its common stock at $6.55 per share, before underwriting discounts, and the exercise in full by the underwriters of their option to purchase 1,350,000 additional shares of common stock at $6.55 per share, before underwriting discounts. The Company received net proceeds of approximately $65,595, after the underwriting discounts and estimated offering costs, which were used to repay amounts outstanding under the Credit Facility.
Note 11 - Income Taxes
The following table presents Callon’sAs of December 31, 2021 and 2020, the net deferred income tax assets and liabilities with respect to its carryforwards and other temporary differences:
U.S. federal net operating loss (“NOL”) utilization was changed by the 2017 Tax Reform for losses incurred in tax years beginning after December 31, 2017. Post-2017 NOLs do not have an expiration period, but may only offset 80%are comprised of the Company’s taxable income in any year of utilization. If not utilized, the Company’s existing federal NOL carryforwards, unaffected by the 2017following:
As a result of the write-down ofManagement monitors company-specific, oil and natural gas industry and worldwide economic factors and assesses the likelihood that the Company’s 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 a net deferred tax asset position at December 31, 2021, driven primarily by the impairments of evaluated oil and gas properties discussedrecognized beginning in Notes 2the second quarter of 2020 and 13,continuing through the fourth quarter of 2020. This limits the ability to consider other subjective evidence such as the Company’s potential for future growth. Since the second quarter of 2020, based on the evaluation of the evidence available, the Company hasconcluded that it is more likely than not that the net deferred tax assets will not be realized. As of December 31, 2021, the valuation allowance balance is $560.8 million, reducing the net deferred tax assets to zero.
Uncertain Tax Positions
.
The following table discloses certain financial data relating to the Company’s oil and natural gas activities, all of which are located in the United States.
Subsequent to December 31, 2017, and through February 23, 2018, the Company drilled eight gross (6.0 net) horizontal wells and completed five gross (3.0 net) horizontal wells and had three gross (3.0 net) horizontal wells awaiting completion.Depletion per unit-of-production, on a BOE basis, amounted to $13.82, $12.81 and $19.74 for the years ended December 31, 2017, 2016, and 2015, respectively. Lease operating expenses per unit-of-production, on a BOE basis, amounted to $5.96, $6.88, and $7.71 for the years ended December 31, 2017, 2016, and 2015, respectively.
Estimated Reserves
The Company’s proved oil and natural gas reserves at December 31, 2017, 2016 and 2015 have been estimated by DeGolyer and MacNaughton, the Company’s current independent petroleum engineers. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
The following tables disclose changes in the estimated net quantities of oil and natural gas reserves, all of which are located onshore within the continental United States:
Total Proved Reserves: The Company ended 2017 with estimated net proved reserves of 136,974 MBOE, representing a 50% increase over 2016 year-end estimated net proved reserves of 91,580 MBOE. The Company added 57,881 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 49 gross (38.2 net) wells. This increase was primarily offset by 2017 production and revisions. The decrease from revisions was primarily due to the removal of 13 proved undeveloped locations as a result of a change in the Company’s development and drilling plans within its operating areas and the removal of certain proved developed vertical well locations..
The Company ended 2016 with estimated net proved reserves of 91,580 MBOE, representing a 69% increase over 2015 year-end estimated net proved reserves of 54,271 MBOE. The Company added 48,477 MBOE primarily from the Company’s acquisition and development efforts in the Permian Basin, where it drilled a total of 29 gross (20.9 net) wells. This increase was primarily offset by 11,168 MBOE related to divestitures, 2016 production and revisions primarily due to pricing.
The Company ended 2015 with estimated net proved reserves of 54,271 MBOE, representing a 65% increase over 2014 year-end estimated net proved reserves of 32,824 MBOE. The increase was primarily due the Company’s development of its properties in the Permian Basin,
where it drilled a total of 36 gross (27.1 net) wells, and acquisitions made during 2015. This increase was primarily offset by 2015 production and revisions.
Extrapolation of performance history and material balance estimates were utilized by the Company’s independent petroleum and geological firm to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to nonproducing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
Proved Undeveloped Reserves: The Company annually reviews its proved undeveloped reserves (“PUDs”) to ensure an appropriate plan for development exists. Generally, reserves for the Company’s properties are booked as PUDs only if the Company has plans to convert the PUDs into proved developed reserves within five years of the date they are first booked as PUDs.
The Company’s PUDs increased 40% to 67,656 MBOE from 48,348 MBOE at December 31, 2017 and 2016, respectively. The Company added 3,267 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, and added 30,198 MBOE from the continued horizontal development of its Permian Basin properties. The increase in the Permian Basin PUDs was partially offset by 5,876 MBOE of revisions primarily due to the removal of 13 PUD locations as a result of a change in the Company’s development and drilling plans within its operating areas and downward revisions to its current PUD locations. In addition,the increase in Permian Basin PUDs was offset by the reclassification of 8,281 MBOE, or 17%, included in the year-end 2016 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $57,019, net.
The Company’s PUDs increased 88% to 48,348 MBOE from 25,654 MBOE at December 31, 2016 and 2015, respectively. The Company added 17,482 MBOE to its PUDs, primarily from acquisitions in the Permian Basin, net of divestitures, and added 12,035 MBOE from the continued horizontal development of its Permian Basin properties, net of revisions. The increase in Permian Basin PUDs was partially offset by the reclassification of 6,823 MBOE, or 27%, included in the year-end 2015 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $43,415, net.
The Company’s PUDs increased 75% to 25,654 MBOE from 14,623 MBOE at December 31, 2015 and 2014, respectively. The Company added 13,774 MBOE to its PUDs, net of revisions, primarily from the continued horizontal development of its Permian Basin properties and from acquisitions in the Permian Basin. The increase in Permian Basin PUDs was partially offset by the reclassification of 2,742 MBOE, or 19%, included in the year-end 2014 PUDs, to PDPs as a result of our horizontal development of Permian Basin properties at a total cost of approximately $55,933, net.
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2017. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Prices are based on the preceding 12-months’ average price based on closing prices on the first day of each month. The following table summarizes the average 12-month oil and natural gas prices net of differentials for the respective periods:
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
Note 14–Other
Contingencies
The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2021.
Leases
committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
In March 2015, the Company decided to terminate its one-year contract for a vertical drilling rig (effective April 2015). The Company paid approximately $3,075 in reduced rental payments over the remainder of the lease term, which ended November 2015. The amount was recognized as rig termination fee on the consolidated statements of operations for
•Increase of 36.2 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 10.1 MMBoe were proved developed reserves;•Decrease of 14.2 MMBoe for revisions of previous estimates that were primarily comprised of:Note 15– Summarized Quarterly Financial Information (Unaudited)◦29.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as we develop our properties in an effort to increase capital efficiency and cash flow generation as well as changes in our development plans, primarily due to the Primexx Acquisition, which resulted in PUDs being moved outside of the five-year development window;
◦13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.
None.On January 11, 2016, the Audit Committee of the Board of Directors of Callon Petroleum Company (the “Company”) approved the engagement of Grant Thornton LLP (“GT”) as the Company’s independent registered public accounting firm for the year ending December 31, 2016. GT informed the Company that it completed the prospective client evaluation process on January 14, 2016. In connection with the selection of GT, also on January 11, 2016, the Audit Committee informed Ernst & Young LLP (“E&Y”) that they would no longer serve as the Company’s independent registered public accounting firm no later than the date of the filing of the Company’s Form 10-K for the 2015 fiscal year. The Audit Committee made its decision in connection with its annual review of the Company’s independent registered public accounting firm and after soliciting proposals from several accounting firms, including E&Y.
During the year ended December 31, 2015 and through January 11, 2016, neither the Company nor anyone on its behalf consulted with GT with respect to either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on the Registrant’s consolidated financial statements, and neither written nor oral advice was provided to the Company that GT concluded was an important factor considered by the Company in reaching a decision as to any accounting, auditing or financial reporting issue; (ii) any matter that was either the subject of disagreement (as defined in Item 304(a)(l)(iv) of Regulation S-K and the related instructions to Item 304 of Regulations S-K) or a reportable event (as defined by Item 304(a)(l)(v) of Regulation S-K).
The report of E&Y on the Company’s consolidated financial statements for the years ended December 31, 2015, did not contain an adverse opinion or disclaimer of an opinion, and was not qualified or modified as to uncertainty, audit scope or accounting principles.
ItemITEM 9A. Controls and Procedures
Management’s report onChanges in Internal Control Over Financial Reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
2021.
Changes in internal control over financial reporting. There were no changes to our internal control over financial reporting during our last fiscal quarter that have materially affected, or are reasonable likely to materially affect, our internal control over financial reporting.
ITEM 9A (T).Controls and Procedures
See Item 9A.
Submissions ofmatters to avote of thesecurityholders.
Not applicable.Report of Independent Registered Public Accounting Firm
Board of Directors and StockholdersCallon 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, 2017, 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, 2017, 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, 2017, and our report dated February 27, 2018 expressed 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 controls over financial reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ GRANT THORNTON LLP
Houston, TexasFebruary 27, 2018
ForThe information concerning Item 10, seerequired by this item is incorporated herein by reference to the definitive proxy statement (the “2022 Proxy Statement”) for our 2022 annual meeting of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018, whichshareholders. The 2022 Proxy Statement will be filed with the Securities and Exchange Commission and is incorporated herein by reference.
SEC not later than 120 days subsequent to December 31, 2021.
ITEM 11.�� Executive Compensation
For information concerning Item 11, see the definitive proxy statement of Callon Petroleum Company relating to the Annual Meeting of Stockholders to be held on May 10, 2018,2022 Proxy Statement, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.SEC not later than 120 days subsequent to December 31, 2021.
ForThe information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon Petroleum Company relatingrequired by this item is incorporated herein by reference to the Annual Meeting of Stockholders to be held on May 10, 2018,2022 Proxy Statement, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.SEC not later than 120 days subsequent to December 31, 2021.
ForThe information concerning Item 13, see the definitive proxy statement of Callon Petroleum Company relatingrequired by this item is incorporated herein by reference to the Annual Meeting of Stockholders to be held on May 10, 2018,2022 Proxy Statement, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.SEC not later than 120 days subsequent to December 31, 2021.
ForThe information concerning Item 14, see the definitive proxy statement of Callon Petroleum Company relatingrequired by this item is incorporated herein by reference to the Annual Meeting of Stockholders to be held on May 10, 2018,2022 Proxy Statement, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.SEC not later than 120 days subsequent to December 31, 2021.
ItemITEM15. Exhibits and Financial Statement Schedules
(a) Documents filed as part of this 2021 Annual Report on Form 10-K:The following is an(1) Financial Statements
(d) Certain schedules and similar attachments have been omitted pursuant to Item 601(a)(5) of Regulation S-K. Callon agrees to furnish a supplemental copy of any omitted schedule or attachment to the SEC upon request.
ItemITEM 16. Form 10-K Summary
None.Not applicable.
SIGNATURES
94
Our lease agreements generally terminate if producing wells have not been drilled on the numberacreage within their primary term or an extension thereof (a period that is generally from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2022, 2023 and 2024 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 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 leased gross and netdevelopment plans.
The proved undeveloped acres in the Permian Basin that will expirereserves associated with acreage expiring over the next three years unless production begins before lease expiration dates. Gross amounts may be more than net amountsare 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 a particular year duemultiple 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 timing of expirations.
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| Net | Gross | ||||||||||||||
| 2018 | 2019 | 2020 | Total | Total | |||||||||||
| Permian Basin | 5,288 | 9,641 | 1,413 | 16,342 | 33,148 | ||||||||||
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.
•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 table above accounts for approximately 99%health and well-being of our net undeveloped acreage (16,496 total net acres).employees and their families by paying 100% of the premiums for our health care plan, which includes telemedicine and an Employee Assistance Program. We are continually engagedalso 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 combinationmonthly in-house leadership development program in 2021. Our leaders support all of drillingour 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 discussions with mineral lessors for lease extensions, renewals, new drillingGeographic Information
For segment reporting purposes, Callon considers all of the current development and operating areas to be one reportable segment: the development units and new leasesproduction of oil and natural gas. All of our 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 address any potential expiration of undeveloped acreage that occurscustomers located in the normal course of our business.
Title to Properties
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.
16
Competition
We operate in the oil and natural gas industry, which is highly competitive. Our business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects our 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 include coverage for general liability insuring onshore operations (including suddengenerally protect against bodily injury and accidental pollution), aviation liability, auto liability, worker’s compensation,property damage, pollution and employer’s liability. The Company carriesother environmental damages, employee benefits, employee injury and control of well insurance for all of its drillingour exploration and production operations.
Corporate Offices
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 amendment and/potential 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 expansion. Some of these requirements carry substantial penalties for failure to comply.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.
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.
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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 EPA,U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures .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 relaterelating 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. Further, the EPA has identified environmental compliance by the energy extraction sector as one of its enforcement initiatives for fiscalIn recent years, 2017-2019, although the outlook for this initiative is unclear with the current administration, and, as a general matter, 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, followingIf 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, 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 is 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 is not necessary. If EPA proposes a rulemaking for revised oil and gas waste regulations in the Consent Decree requires that the EPA take final action following notice and comment rulemaking no later than July 15, 2021. Non-exempt waste is subject to more rigorous and costly disposal requirements. Anyfuture, 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 so–called 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
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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 wastewater 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 includingor 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 “CleanClean 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 hasand the Corps issued a final rulesrule on the federal jurisdictional reach over waters of the United States that may constitute an expansionin 2015, which never 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 jurisdiction overdistrict court in August 2021. The EPA is undergoing a rulemaking process to redefine the definition of waters of the United States. The ruleStates; in the interim, the EPA is utilizing the subject of various legal challenges. 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. For example, on August 16, 2012,Obtaining or renewing permits also has the EPA published final regulations underpotential to delay the federal Clean Air Act that establish new emission controls fordevelopment of oil and natural gas production and processing operations, which regulations are discussed in more detail below in “Regulation of Hydraulic Fracturing.” These laws and regulations may increase the costs of compliance for some facilities we own or operate, and federalprojects. 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. Obtaining
In June 2016, the EPA finalized regulations establishing New Source Performance Standards, known as Subpart OOOOa, for methane and volatile organic compounds from new and modified oil and natural gas production and natural gas processing and transmission facilities. In September 2020, the EPA finalized two sets of amendments to the 2016 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 2020 Policy Rule. On June 30, 2021, President Biden signed a Congressional Review Act (the “CRA”) resolution passed by Congress that revoked the 2020 Policy Rule. The CRA did not address the 2020 Technical Rule.
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Further, on November 15, 2021, 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 source types that have never been regulated under the 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 renewingmodify 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, hasand result in increased expenditures for pollution control equipment, the potential to delaycosts of which could be significant.
Climate Change. Numerous reports from scientific and governmental bodies such as the developmentSixth 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 projects.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. On June 1, 2017, President Trump announced that the U.S. would withdraw from the Paris Agreement and completed the process of withdrawing from the Paris Agreement on November 4, 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 became effective on February 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 joined 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) 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 adopted in recent years. However, the United States House of Representatives passed H.R. 5376, known as the Build Back Better Act, on November 3, 2016,2021. The House version of the EPA expanded itsbill targets methane from oil and gas sources by proposing to 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 coverage inprograms 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 industry with additional regulated equipment categories,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 addition of new rules limiting methane emissions from new or modified sites and equipment. The EPA attempted to suspend enforcement of the methane rule, but this action was ruled improper. EPA is reported to be considering rulemaking to rescind or revise the rule. Simultaneously with the additional methane rules, EPA released a rule defining site aggregation for air permitting purposes. Should the EPA reconsider this definition, some sites could require additional permitting under the Clean Air Act, an outcome that could result in costs and delays to our operations.
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. The GHG reporting threshold was recently crossed due to drilling activity, acquisitions,
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 production growth.
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such litigation, we produce. Thecould 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 future programs cannot be predicted, but we do not expect our operations to be affected any differently than other similarly situated domestic competitors.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, in June 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.
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. TheFor example, Texas Legislature adopted new legislation requiring oil and gas operators to publicly disclose the chemicals used in the hydraulic fracturing process, effective as of September 1, 2011. The Texas Railroad Commission has adopted rules and regulations implementing this legislation that apply to all wells for which the Railroad Commission issues an initial drilling permit after February 1, 2012. The new 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 Texas Railroad Commission.
RRC.
Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some casecases 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 countryU.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 that specific chemicals used in the fracturing process could adversely affect groundwater.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 newly enacted or 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. For 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 has 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
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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 and Endangered Species 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 July 16, 2020, the Council on Environmental Quality revised NEPA’s implementing regulations in an effort designed to streamline project approvals. Among other revisions, the rules 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 rule also eliminated the current “direct,” “indirect,” or “cumulative” categories of effects. 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 coalition 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 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 including regulation ofby FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters, primarily by the Federal Energy Regulatory Commission, or FERC. Federal and statematters. State regulations govern the rates, terms, and other terms forconditions of service associated with access to intrastate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transmissiontransportation 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.
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Exports of US CrudeU.S. Oil Production and Natural Gas Production. The In December 2015, the federal government has recently ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. TheU.S. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry is that ending the prohibitionend of exports of oil produced in the US will beU.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy (“DOE”) authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, which are expected to increase significantly with the changes taking place in the Mexican government’s regulations of the energy sector in Mexico. In addition, the DOE authorizesand the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. In the third quarter ofSince 2016, the first quantities of natural gas produced in the lower 48 states of the U.S. werehas been exported as LNG from the first of several LNG export facilities being developed and constructed in the U.S. Gulf Coast region. While itLNG export capacity has steadily increased in recent years, and is too recent an eventexpected to determine the impactcontinue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this change may have on our operations or our sales of natural gas, the perceptionsustained growth in the industry is that thisexports 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:
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. Although the U.S. Army Corps of Engineers does notSome state agencies and municipalities require bonds or other financial assurances some state agencies and municipalities do have such requirements.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.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 1978.1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for sales“first sales” of domestic natural gas, sold in “first sales,” which include all of our sales of our own production. Under the Energy Policy Act of 2005, FERC has substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess substantial civil penalties.
Under the Energy Policy Act of 2005 (“EPAct”EPAct 2005”), Congress amended the Natural Gas Act (“NGA”)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 substantial civil penalties.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 natural gas transportation 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. Commencing inIn 1985, FERC promulgatedbegan 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 nondiscriminatorynon-unduly discriminatory transportation services to producers, marketers and otherall 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 salestransportation 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-discriminatorynot unduly discriminatory basis at cost-based rates or atnegotiated rates, both of which are subject to FERC approval. 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
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means by which a shipper releases its pipeline capacity to another potential shipper, which provisions include 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 produce evidence ofprovide information concerning the greenhouse gas (“GHG”)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, whichand required FERC to revise its environmental impact statement for the proposed pipeline to take into accountanalyze potential GHG carbon emissionsemission from the specific downstream power plants usingthat the pipeline was designed to serve. In March 2021, FERC assessed 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 it will also consider state GHG emission reduction targets, to the 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 transported bypipeline projects, including the new pipeline. It is too early to determine theupstream indirect impacts of this Court decision, but it could be significant.
related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at 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 transportation 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, (“NGPSA”), 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, the 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 2015, the2019, PHMSA issued proposedfinalized 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 operators establishpipelines 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 timeline for inspections of affected pipelines following extreme weather events or natural disasters. If such revisionsrulemaking with respect to gathering linelines, 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 liquidsLNG 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 enacted by PHMSA, we could incur significant expenses.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 the FERC under the Interstate Commerce Act. TheAct (“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.
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Further, interstate common carrier oil pipelines must provide service on a non-discriminatorynot unduly discriminatory basis under the Interstate Commerce Act (“ICA”),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 pipelines. It is too recent an event totime, 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 crude 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, (“HMR”), including Emergency Orders by the FRA and new regulations being proposedinitially established on May 8, 2015 by the PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids.
liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018. In October 2015, theJuly 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 new safety regulations for hazardous liquid pipelines, including a requirement that all hazardous liquid pipelines have a system for detecting leaks and establish a timeline for inspections of affected pipelines following extreme weather events or natural disasters.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 (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 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 affect 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. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to any 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
AvailableInformation
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. You may read and copy any materials we file with the SEC at the SEC’s Public Reference Room at 100 F Street, NE., Washington, DC 20549. You may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. The SEC also maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers, like Callon, that file electronically with 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 Reserve, and Nominating and GovernanceESG, and Operations and Reserves Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure by a Current Report on Form 8-K and 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: Chief Financial Officer,General Counsel, Callon Petroleum Company, P.O. Box 1287, Natchez, MS 39121.2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042.
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 condition.condition. Our success is highly dependent on prices for oil and natural gas, which have been extremely volatile in recent years. Approximately 77% of our anticipated 2018 production, on a BOE basis, is oil. Starting inyears been, and we expect will continue to be, extremely volatile. During the second half of 2014, thefive years ended December 31, 2021, NYMEX price for a barrel of oil fell sharply, from a price of $105.37 on June 30, 2014 to $26.21 on February 11, 2016. During 2017, NYMEXWTI prices ranged from a high of $85.64 per barrel on October 26, 2021 to a low of $42.53-$36.98 per Bblbarrel on June 21, 2017 toApril 20, 2020, and NYMEX Henry Hub prices ranged from a high of $60.42$23.86 per BblMMBtu on December 29, 2017. In addition, NYMEX prices forFebruary 17, 2021 to a low of $1.33 per MMBtu on 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 have been low compared with historical prices. Extended periods of low prices for oil or natural gas will have a material adverse effect on us.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 economicmacro-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. PricesThese 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 non-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, and natural gas, willand 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.
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 sustained period of weakness, our future business, financial condition, results of operations, liquidity, and ability to finance planned capital 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 present value, discounted at 10%,PV-10 of future net cash flows fromour estimated net proved reserves, using the preceding 12-months’ average oil and natural gas prices,12-Month Average Realized Prices, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs of our oil and natural gas properties exceed this “ceiling test” 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 2to our Consolidated Financial Statements as well as the Supplemental Information on Oil and 13Natural Gas Operations for additional information.
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 Footnotessector 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, social and governance (“ESG”) activism
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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.
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, 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 operate our business and 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 and qualified personnel. As a result of such shortage, the costs and delivery times of rigs, equipment and supplies often increase substantially, as well as the wages and costs of drilling rig crews and other experienced personnel and oilfield services, while the quality of these services and equipment may suffer. This impact may be magnified to the Financial Statements for additional information.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.
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 ceiling test limitation. The ceiling test calculation asCOVID-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 December 31, 2017 was calculated usingoperations, and cash flows. However, the average annual realized prices usedextent 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 determining the estimated future net cash flows from proved reservesexpected time frame, is uncertain and depends on various factors that we cannot predict, including the following: the severity and duration of $51.34 per barrelthe 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 $2.98 per Mcf of natural gas. Oil prices continuegas, which may be reduced on a prolonged or permanent basis due to fluctuate and we may experience ceiling test write-downsa structural shift in the future. Any future ceiling test cushion,global economy in the way people work, travel, and interact, or in connection with a global recession or depression; any impairment in the risk we may incur write-downsvalue of our tangible or impairments, willintangible assets which could be subject to fluctuationrecorded as a result of acquisitiona weaker economic conditions or divestiture activity. 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
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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,
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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 turn out to 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. These estimates are based upon various assumptions, including assumptions required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. The process of estimating oil and natural gas reserves is complex. This processcomplex 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 report.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 present valuePV-10 of future net cash flows from our estimated net 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 estimated discounted future net cash flowsPV-10 from our estimated proved reserves at December 31, 20172021 on average 12-month pricesthe 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. At December 31, 2017, approximately 35% of the discounted present value of our estimated net proved reserves consisted of PUDs. PUDs represented 49% of total proved reserves by volume. 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 10% discount factor that we useused to calculate the net present value of future net revenues and cash flowsPV-10 may not necessarily be the most appropriate discount factor based on our cost of capital in effect from time to time and the risks associated with our business and the oil and gas industry in general.industry.
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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 among others:
oil and natural gas prices;
prices, the availability and cost of capital;
capital, availability and cost of drilling, completion and production services and equipment;
equipment, lease expirations;
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 proved undeveloped reservesPUDs 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 49%43% of our total estimated proved reserves as of December 31, 2017,2021 were proved undeveloped reserves and may not be ultimately developed or produced. Recovery of proved undeveloped reserves requires significant capital expenditures and successful drilling operations.PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume that substantialsignificant capital expenditures are requiredwill be made to develop such reserves. We cannot be certain that the estimated costs of the development ofcapital 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 proved undeveloped reservesPUDs 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
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insurance coverage for protecting against cyber securitycybersecurity risks may not be sufficient. Further, as cyber-attackscyberattacks 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 cyber-attacks.
cyberattacks.
Risks Related to Our Indebtedness and 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.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. Historically, we have fundedWe intend to fund our capital expenditures through a combination of cash flows from operations and, if needed, borrowings from financial institutions, the sale of public debt and equity securities, and asset dispositions. In 2017, our total operational capital expenditures, including expenditures for drilling, completion and facilities, were approximately $420 million on a cash basis ($463 million on an accrual, or GAAP, basis). Our 2018 budget for operational capital expenditures is currently estimated to be approximately $500 to $540 million (on an accrual, or GAAP, basis).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 borrowing baseability to borrow under our Credit Facility or our revenuescash flows from operations decrease, as a result of lower oil or natural gas prices, operating difficulties, declines in reserves or for any other reason, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. If additional capital is needed, we may not be ableThe failure to obtain debt or equityadditional financing on terms favorableacceptable to us, or at all. If cash generated by operations or cash available under our Credit Facility is not sufficient to meet our capital requirements, the failure to obtain additional financingall, could result in a curtailment of our operations relating to development of our drilling locations, which in turn could lead to a possible expiration of our leases and a decline in our estimated net proved reserves,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 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 our Credit Facility and the indentureagreements governing our 6.125% Senior Notesindebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities.Our Credit Facility and the indentureindentures governing our 6.125% Senior Notessecond 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; and
or engage in certain other transactions without the prior consent of the holders or 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 andor the indentureindentures governing the 6.125 % Senior Notes,our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
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;
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
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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 earnings are exposed to interest rate risk associated with borrowings under our Credit Facility whichmake 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 2.00%1.00% to 3.00%, depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base. LIBOR is the subject of national, international and other regulatory guidance and proposals for reform and is currently being phased-out. At this time, 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 phase-out or replacement of LIBOR. 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 borrowing baseability to borrow under our Credit Facility may be reducedrestricted to an amount below the amount of borrowings outstanding under such facilities.thereunder or to a lesser amount than what we expect due to future borrowing base reductions or restrictions contained in our other debt agreements. The borrowing base and elected commitment amount under our Credit Facility is currently $700$1.6 billion, and as of December 31, 2021, we had an aggregate principal balance of $785.0 million with elected commitments of $500 million. In theoutstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future we may not be able to access adequate funding under our Credit Facility as a result of a 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. In addition, we cannot borrow amounts aboveobligations may cause us to not be able to access adequate funding under the elected commitments, even ifCredit Facility. The lenders have sole discretion in determining the amount of the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. Ourand may cause our borrowing base is subject to redeterminations semi-annually,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 next scheduled borrowing base redetermination is expectedability to occur on or about May 2018.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, inwe 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. AnyAlso, 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. TheIn addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. In addition, anyFor 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. Our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition. We may not be able to consummate those dispositions, and the proceeds of any such disposition may not be adequate to meet any debt service obligations then due. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations.
We cannot assure yoube 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.
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Risks Related to Acquisitions
We may be unable to integrate successfully the operations of acquisitions with our operations, and we may not be insured againstrealize 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 Primexx Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate future acquisitions successfully could adversely affect our financial condition and results of operations.
Our acquisitions may involve numerous risks, including those related to:
•operating a larger, more complex combined organization and adding operations;
•assimilating the assets and operations of the risksacquired 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. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our businesstwo 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 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 exposed from ongoing or legacy operations. In accordanceconsistent with industry practice,practices, we maintain insurance against some, but notcan give no assurance that we have identified or will identify all of the operating risks to which our business is exposed. We cannot assure you that our insurance will be adequate to cover all lossesexisting or liabilities related to our currentpotential problems associated with such properties or legacy operations. Also, we cannot predict the continued availability of insurance at premium levels that justify its purchase. No assurance can be given that we will be able to maintain insurancemitigate 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 the future at ratesproperties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we consider reasonablemay not be able to acquire oil and may elect nonenatural gas properties that contain economically recoverable reserves or minimal insurance coverage. The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effectbe able to complete such acquisitions on our financial condition and operations.acceptable terms.
Risks Related to Our Hedging Program
Our hedging program may limit potential gains from increases in commodity prices, or may result in losses, or may be inadequate to protect us against continuing and prolonged declines in commodity prices.We enter into hedging 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, 20172021 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 assure yoube certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from fluctuations in oil and natural gas prices. At December 31, 2017, the Company’s hedging portfolio, linked to NYMEX benchmark pricing, covers approximately 5,842 MBbls and 4,086 BBtu of our expected oil and natural gas production, respectively, for calendar year 2018. We also have commodity hedging contracts linked to Midland WTI basis differentials relative to Cushing covering approximately 5,289 MBbls of our expected oil production for calendar year 2018. These hedges may be inadequate to 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 willwould not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition wouldmay be negatively impacted.
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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.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 and we may not be able to realize the benefit of the derivative contract. During periods of falling commodity prices, our hedging transactions expose us to risk of financial loss if our counterparty to a derivatives transaction fails to perform its obligations under a derivatives transaction. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform. Evenperform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending uponon market conditions.conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.
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 “Regulations.“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 wilderness or other protected areas;and wilderness;
•impose penalties andor other sanctions for accidental and/or unpermitted spills or releases from our operations; andor
•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, permitting,storage, transport, remediation or cleanupdisposal 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.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, greenhouse gasesengine and other
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equipment emissions, GHGs and hydraulic fracturing. Under the 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 particularly natural gas, 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,"“underground injection” and to require federal permitting and regulatory control of hydraulic fracturing and to require disclosure of the chemical constituents of the fluids used in the fracturing process.but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, the EPA has taken the position thatregulates hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection ControlUIC program, specifically as "Class II"“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. In addition, the BLM previously published final rules governing hydraulic fracturing on federal and Indian lands, which rules have been rescinded or suspended, but litigation is ongoing regarding the rules.
industry remains a possibility.
In some areas of Texas, including the Eagle Ford and Permian, 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 governing Texas regulatory agencyRRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the Texas state agencyRRC were to decline to issue permits for, or limitimpose new limits on the volumes of, new injection wells into the formations that we currently utilized by us,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, pursuant to legislation adopted by the State of Texas in June 2011,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, in 2013, the RRC issued the "wellThe RRC’s “well integrity rule," whichrule” includes new 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 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 and/or hydraulic fracturing in particular.
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
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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 “greenhouse gases” (“GHG”)GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could result in increasedadversely impact our operating costs and reduced demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken
steps to reduce emissions of greenhouse gases.GHGs. The EPA has finalized a series of greenhouse gasGHG monitoring, reporting and emissions control rules for the oil and natural gas industry,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 greenhouse gasesGHGs primarily through the development of greenhouse gasGHG emission inventories and/or regional greenhouse gasGHG cap-and-trade programs. While we are subject to certain federal greenhouse gasGHG 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 greenhouse gasGHG rules and regulations, see “Regulations.“Business and Properties—Regulations.”
In December 2015, the United States participated in the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in Paris, France. The resultingnearly 200 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake "ambitious efforts"“ambitious efforts” to limit the average global temperature and to conserve and enhance sinks and reservoirs of GHGs.temperature. The Paris Agreement went into effect on November 4, 2016. The Paris Agreement2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. However, onOn June 1, 2017, President Trump announced that the United StatesU.S. would withdraw from the Paris Agreement. It is not clear what stepsAgreement and completed the Trump Administration plans to take to withdrawprocess of withdrawing from the Paris Agreement whetheron November 4, 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 became effective on February 19, 2021. In addition, in September 2021, President Biden publicly announced the Global Methane Pledge, a new agreement can be negotiated,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 joined the pledge. The COP26 concluded with the finalization of the Glasgow Pact, which stated long-term global goals (including those in the Paris Agreement) 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 what terms would be included in such an agreement.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.
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, 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
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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, andincluding the scope of relevant definitions and/or exemptions, still remain to be finalized. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet approved 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 has not yet issued a final rule.pending. The CFTC has 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.
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. Finally, the legislation was intended, in part, to reduce the volatility of oil, natural gas and natural gas liquids prices, which some legislators attributed to speculative trading in derivatives and commodity instruments. Our revenues could t 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 Risks
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 effective date of 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% 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”), 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 Code) at any time
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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 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 the following: 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.
Tax laws and regulations may change over time and the recently passed comprehensive tax reform billsuch changes 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 as the Tax Cuts and Jobs Act (the "Tax Act") that significantly reforms the Internal Revenue Code of 1986, as amended (the "Code"). The Tax Act, among other things, (i) permanently reduces 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 limitations on the utilization of net operating losses, and (v) provides for more general changes to the taxation of corporations, including changes to cost recovery rules and to the deductibility of interest expense, which may impact the taxation of oil and gas companies. The Tax Act is complex and far-reaching and we cannot predict with certainty the resulting impact its enactment has on us. The ultimate impact of the Tax Act may differ from our estimates due to changes in interpretations and assumptions made by us as well as additional regulatory guidance that may be issued and any such changes in interpretations or assumptions could adversely affect our business and financial condition. See Note 11 to our consolidated financial statements included elsewhere in this Annual Report for additional information.
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 Permian 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 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.
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The loss of key personnel, or inability to employ a sufficient number of qualified 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. Also, we may experience 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 energy industry. If we are unsuccessful in our efforts to attract and retain sufficient qualified personnel on terms acceptable to us, or do so at rates necessary to maintain our competitive position, our business could be adversely affected.
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 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 boardBoard of directorsDirectors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the Delaware General Corporation Law.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
General Risk Factors
We may be subject to the actions of activist shareholders. We have been the subject of increased activity byan activist shareholders.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 boardBoard of directorsDirectors 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. We do notWhile 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 following table sets forthCompany’s common stock began trading on a split-adjusted basis on the highNYSE at the market open on August 10, 2020. All share and low sale prices 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 reported fora result of the periods indicated.
| Common Stock Price | ||||||||||||||||
| 2017 | 2016 | |||||||||||||||
| High | Low | High | Low | |||||||||||||
| First quarter | $ | 16.32 | $ | 10.97 | $ | 9.05 | $ | 4.21 | ||||||||
| Second quarter | 13.92 | 9.63 | 12.56 | 8.15 | ||||||||||||
| Third quarter | 11.74 | 9.34 | 15.91 | 10.34 | ||||||||||||
| Fourth quarter | 12.50 | 9.76 | 18.53 | 12.45 | ||||||||||||
reverse stock split.
Holders
As of February 23, 201818, 2022 the Company had approximately 2,7151,182 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. The declarationbusiness and paymentcontinue to pay down debt. However, we continuously monitor many internal and external 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 twoa broad-based stock performance indices.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, 2016 through December 31, 2021. The companies in the peer group include Centennial Resource Development, Inc., Dow Jones US SelectLaredo Petroleum, Inc., Magnolia Oil & Gas ExplorationCorporation, Matador Resources, Inc., PDC Energy, Inc., Ranger Oil Corporation and Production Index (“DJ US Select O&G E&P Index”) and Susquehanna International Group, LLP Oil Exploration & Production Index (“SIG Oil E&P Index”) from December 31, 2012, through December 31, 2017.SM Energy Company. The SIG Oil E&P Index is no longer an active index and the Company plans to replace it with the DJ US Select O&G E&P Index, which is commonlyCompany’s historical stock prices used by the Company’s peer group. Consequently, this index has been added toin the graph below and we expecthave been retroactively adjusted to include it in future year’s performance graphs.
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.filing
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Comparison of Five YearCumulative Total Return
Assumes Initial Investment of $100
December 201731, 2021
| 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.
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| For the Year Ended December 31, | ||||||||||||||||||||||||
| Company/Market/Peer Group | 2012 | 2013 | 2014 | 2015 | 2016 | 2017 | ||||||||||||||||||
| Callon Petroleum Company | $ | 100.00 | $ | 138.94 | $ | 115.96 | $ | 177.45 | $ | 327.02 | $ | 258.51 | ||||||||||||
| S&P 500 Index - Total Returns | 100.00 | 132.39 | 150.51 | 152.59 | 170.84 | 208.14 | ||||||||||||||||||
| DJ US Select O&G E&P | 100.00 | 131.24 | 115.57 | 87.27 | 109.82 | 110.58 | ||||||||||||||||||
| SIG Oil Exploration & Production Index | 100.00 | 128.46 | 91.28 | 48.44 | 62.74 | 62.74 | ||||||||||||||||||
ITEM 6. Selected Financial DataReserved
| For the Year Ended December 31, | ||||||||||||||||||||
| 2017 | 2016 | 2015 | 2014 | 2013 | ||||||||||||||||
| Statement of Operations Data | ||||||||||||||||||||
| Operating revenues | ||||||||||||||||||||
| Oil and natural gas sales | $ | 366,474 | $ | 200,851 | $ | 137,512 | $ | 151,862 | $ | 102,569 | ||||||||||
| Operating expenses | ||||||||||||||||||||
| Total operating expenses | $ | 225,028 | $ | 248,328 | $ | 346,622 | $ | 113,592 | $ | 91,905 | ||||||||||
| Income (loss) from operations | 141,446 | (47,477 | ) | (209,110 | ) | 38,270 | 10,664 | |||||||||||||
Net income (loss) (a) | 120,424 | (91,813 | ) | (240,139 | ) | 37,766 | 4,304 | |||||||||||||
| Income (loss) per share ("EPS") | ||||||||||||||||||||
| Basic | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | $ | 0.67 | $ | (0.01 | ) | |||||||
| Diluted | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | $ | 0.65 | $ | (0.01 | ) | |||||||
| Weighted average shares outstanding for Basic EPS | 201,526 | 126,258 | 65,708 | 44,848 | 40,133 | |||||||||||||||
| Weighted average shares outstanding for Diluted EPS | 202,102 | 126,258 | 65,708 | 45,961 | 40,133 | |||||||||||||||
| Statement of Cash Flows Data | ||||||||||||||||||||
| Net cash provided by operating activities | $ | 229,891 | $ | 120,774 | $ | 89,319 | $ | 94,387 | $ | 54,475 | ||||||||||
| Net cash used in investing activities | (1,072,532 | ) | (866,287 | ) | (259,160 | ) | (452,501 | ) | (79,804 | ) | ||||||||||
| Net cash provided by (used in) financing activities | 217,643 | 1,397,282 | 170,097 | 356,070 | 27,202 | |||||||||||||||
| Balance Sheet Data | ||||||||||||||||||||
| Total oil and natural gas properties | $ | 2,513,491 | $ | 1,475,401 | $ | 711,386 | $ | 742,155 | $ | 324,187 | ||||||||||
| Total assets | 2,693,296 | 2,267,587 | 788,594 | 863,346 | 423,953 | |||||||||||||||
Long-term debt (b) | 620,196 | 390,219 | 328,565 | 321,576 | 75,748 | |||||||||||||||
| Stockholders' equity | 1,855,966 | 1,733,402 | 362,758 | 433,735 | 279,094 | |||||||||||||||
| Proved Reserves Data | ||||||||||||||||||||
| Total oil (MBbls) | 107,072 | 71,145 | 43,348 | 25,733 | 11,898 | |||||||||||||||
| Total natural gas (MMcf) | 179,410 | 122,611 | 65,537 | 42,548 | 17,751 | |||||||||||||||
| Total (MBOE) | 136,974 | 91,580 | 54,271 | 32,824 | 14,857 | |||||||||||||||
Standardized measure (c) | $ | 1,556,682 | $ | 809,832 | $ | 570,890 | $ | 579,542 | $ | 283,946 | ||||||||||
ITEM 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations
The following management’s discussion and analysis describes the principal factors affecting the Company’sour results of operations, liquidity, capital resources and contractual cash obligations. This discussion 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. All
A discussion and analysis of our filingsthe Company’s financial condition and results of operations for the year ended December 31, 2019 can be found in “Part II, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations” of its Annual Report on Form 10-K for the year ended December 31, 2020, which was filed with the SEC are available free of charge through our website as soon as reasonably practicable after we file them with, or furnish them to, the SEC. Information on our website does not form part of this report on Form 10-K.February 25, 2021.
General
We are an independent oil and natural gas company established in 1950. We are focused on the acquisition, development, exploration and exploitationdevelopment of unconventional, onshore, oil and natural gas reserveshigh-quality assets in the Permian Basin. Theleading 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 Basin is located in West Texas, and southeastern New Mexico and is comprised of three primary sub-basins:as well as the Midland Basin, the Delaware Basin, and the Central Basin Platform. We have historically been focused on the Midland Basin and more recently entered the Delaware Basin through an acquisition completedEagle Ford in February 2017.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, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales.shales, and the Eagle 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. Our production was approximately 78% oil
Financial and 22% natural gasOperational Highlights
For discussion of our significant financial and operational highlights for the year ended December 31, 2017. On December 31, 2017, our net acreage position2021, please see “Part 1. Items 1 and 2. Business and Properties — Overview — Major Developments in the Permian Basin was 57,481 net acres.2021”.
44
| Twelve Months Ended December 31, | |||||||||||
| (in thousands) | 2017 | 2016 | 2015 | ||||||||
| Net cash provided by operating activities | $ | 229,891 | $ | 120,774 | $ | 89,319 | |||||
| Net cash used in investing activities | (1,072,532 | ) | (866,287 | ) | (259,160 | ) | |||||
| Net cash provided by financing activities | 217,643 | 1,397,282 | 170,097 | ||||||||
| Net change in cash and cash equivalents | $ | (624,998 | ) | $ | 651,769 | $ | 256 | ||||
| Twelve Months Ended December 31, | ||||||||||||
| 2017 | 2016 | $ Change | ||||||||||
| Operational expenditures | $ | 355,833 | $ | 143,856 | $ | 211,977 | ||||||
| Seismic, leasehold and other | 16,385 | 13,640 | 2,745 | |||||||||
| Capitalized general and administrative costs | 17,016 | 12,679 | 4,337 | |||||||||
| Capitalized interest | 30,605 | 19,857 | 10,748 | |||||||||
Total capital expenditures(a) | 419,839 | 190,032 | $ | 229,807 | ||||||||
| Acquisitions | 718,456 | 654,679 | 63,777 | |||||||||
| Acquisition deposits | (45,238 | ) | 46,138 | (91,376 | ) | |||||||
| Proceeds from the sale of mineral interest and equipment | (20,525 | ) | (24,562 | ) | 4,037 | |||||||
| Total investing activities | $ | 1,072,532 | $ | 866,287 | $ | 206,245 | ||||||
| | Twelve Months Ended December 31, | ||||||||||
| | 2017 | 2016 | $ Change | ||||||||
| Net borrowings on Credit Facility | $ | 25,000 | $ | (40,000 | ) | $ | 65,000 | ||||
| Net borrowings on term loans | — | (300,000 | ) | ||||||||
| Issuance of 6.125% Senior Notes | 200,000 | 400,000 | (200,000 | ) | |||||||
| Premium on the issuance of 6.125% Senior Notes | 8,250 | — | 8,250 | ||||||||
| Issuance of common stock | — | 1,357,577 | (1,357,577 | ) | |||||||
| Payment of preferred stock dividends | (7,295 | ) | (7,295 | ) | — | ||||||
| Payment of deferred financing costs | (7,194 | ) | (10,793 | ) | 3,599 | ||||||
| Tax withholdings related to restricted stock units | (1,118 | ) | (2,207 | ) | 1,089 | ||||||
| Net cash provided by financing activities | $ | 217,643 | $ | 1,397,282 | $ | (1,179,639 | ) | ||||
| | Payments due by Period | |||||||||||||||||||
| | Total | < 1 Year | Years 2 - 3 | Years 4 - 5 | >5 Years | |||||||||||||||
6.125% Senior Notes (a) | $ | 600,000 | $ | — | $ | — | $ | — | $ | 600,000 | ||||||||||
Credit Facility (b) | 25,000 | — | — | 25,000 | — | |||||||||||||||
Interest expense and other fees related to debt commitments (c) | 262,192 | 39,958 | 79,915 | 78,006 | 64,313 | |||||||||||||||
Drilling rig leases (d) | 61,732 | 29,482 | 31,602 | 648 | — | |||||||||||||||
| Office space lease and other commitments | 14,858 | 3,935 | 7,543 | 3,380 | — | |||||||||||||||
Asset retirement obligations (e) | 6,020 | 1,295 | — | — | 4,725 | |||||||||||||||
| Total contractual obligations | $ | 969,802 | $ | 74,670 | $ | 119,060 | $ | 107,034 | $ | 669,038 | ||||||||||
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 | % | |||||||||||||||||||||
45
| Twelve Months Ended December 31, | ||||||||||||||||||||||||||
| 2017 | 2016 | Change | % Change | 2015 | Change | % Change | ||||||||||||||||||||
| Net production: | ||||||||||||||||||||||||||
| Oil (MBbls) | 6,557 | 4,280 | 2,277 | 53 | % | 2,789 | 1,491 | 53 | % | |||||||||||||||||
| Natural gas (MMcf) | 10,896 | 7,758 | 3,138 | 40 | % | 4,312 | 3,446 | 80 | % | |||||||||||||||||
| Total (MBOE) | 8,373 | 5,573 | 2,800 | 50 | % | 3,508 | 2,065 | 59 | % | |||||||||||||||||
| Average daily production (BOE/d) | 22,940 | 15,227 | 7,713 | 50 | % | 9,610 | (9,595 | ) | (100 | )% | ||||||||||||||||
| % oil (BOE basis) | 78 | % | 77 | % | 80 | % | ||||||||||||||||||||
Average realized sales price (excluding impact of cash settled derivatives): | ||||||||||||||||||||||||||
| Oil (Bbl) | $ | 49.16 | $ | 41.51 | $ | 7.65 | 18 | % | $ | 44.88 | $ | (3.37 | ) | (8 | )% | |||||||||||
| Natural gas (Mcf) | 4.05 | 2.99 | 1.06 | 35 | % | 2.86 | 0.13 | 5 | % | |||||||||||||||||
| Total (BOE) | $ | 43.77 | $ | 36.04 | $ | 7.73 | 21 | % | $ | 39.20 | $ | (3.16 | ) | (8 | )% | |||||||||||
Average realized sales price (including impact of cash settled derivatives): | ||||||||||||||||||||||||||
| Oil (Bbl) | $ | 47.78 | $ | 45.67 | $ | 2.11 | 5 | % | $ | 56.82 | $ | (11.15 | ) | (20 | )% | |||||||||||
| Natural gas (Mcf) | 4.10 | 3.00 | 1.10 | 37 | % | 3.26 | (0.26 | ) | (8 | )% | ||||||||||||||||
| Total (BOE) | $ | 42.76 | $ | 39.25 | $ | 3.51 | 9 | % | $ | 49.18 | $ | (9.93 | ) | (20 | )% | |||||||||||
Oil and natural gas revenues (in thousands): | ||||||||||||||||||||||||||
| Oil revenue | $ | 322,374 | $ | 177,652 | $ | 144,722 | 81 | % | $ | 125,166 | $ | 52,486 | 42 | % | ||||||||||||
| Natural gas revenue | 44,100 | 23,199 | 20,901 | 90 | % | 12,346 | $ | 10,853 | 88 | % | ||||||||||||||||
| Total | $ | 366,474 | $ | 200,851 | $ | 165,623 | 82 | % | $ | 137,512 | $ | 63,339 | 46 | % | ||||||||||||
| Additional per BOE data: | ||||||||||||||||||||||||||
Sales price (a) | $ | 43.77 | $ | 36.04 | $ | 7.73 | 21 | % | $ | 39.20 | $ | (3.16 | ) | (8 | )% | |||||||||||
Lease operating expense (b) | 5.46 | 6.56 | (1.10 | ) | (17 | )% | 7.48 | (0.92 | ) | (12 | )% | |||||||||||||||
| Gathering and treating expense | 0.50 | 0.32 | 0.18 | 56 | % | 0.23 | 0.09 | 39 | % | |||||||||||||||||
| Production taxes | 2.67 | 2.13 | 0.54 | 25 | % | 2.79 | (0.66 | ) | (24 | )% | ||||||||||||||||
| Operating margin | $ | 35.14 | $ | 27.03 | $ | 8.11 | 30 | % | $ | 28.70 | $ | (1.67 | ) | (6 | )% | |||||||||||
| 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) Reflects calendar average daily spot market prices.
46
Revenues
The following tables are intended to reconciletable reconciles the changechanges in oil, natural gas, NGLs, and total revenue for the respective periodsperiod presented by reflecting the effect of changes in volume and in the underlying commodity prices.
| (in thousands) | Oil | Natural Gas | Total | |||||||||
| Revenues for the year ended December 31, 2014 | $ | 139,374 | $ | 12,488 | $ | 151,862 | ||||||
| Volume increase | 90,398 | 11,774 | 102,172 | |||||||||
| Price decrease | (104,606 | ) | (11,916 | ) | (116,522 | ) | ||||||
| Net decrease | (14,208 | ) | (142 | ) | (14,350 | ) | ||||||
| Revenues for the year ended December 31, 2015 | $ | 125,166 | $ | 12,346 | $ | 137,512 | ||||||
| Volume increase | 66,916 | 9,856 | 76,772 | |||||||||
| Price increase (decrease) | (14,430 | ) | 997 | (13,433 | ) | |||||||
| Net increase | 52,486 | 10,853 | 63,339 | |||||||||
| Revenues for the year ended December 31, 2016 | $ | 177,652 | $ | 23,199 | $ | 200,851 | ||||||
| Volume increase | 94,518 | 9,383 | 103,901 | |||||||||
| Price increase | 50,204 | 11,518 | 61,722 | |||||||||
| Net increase | 144,722 | 20,901 | 165,623 | |||||||||
| Revenues for the year ended December 31, 2017 | $ | 322,374 | $ | 44,100 | $ | 366,474 | ||||||
| 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 | % | ||||||||||||||||||||
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 | %) | ||||||||||||||||||||||||||||||||||||||||
Lease Operating Expenses. Lease operating expenses for the year ended December 31, 2021 increased by 5% to $203.1 million compared to $194.1 million for the same period of 2,125 MBbls2020, primarily due to operating expenses attributable to wells placed onthat 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, 2021 increased to $5.82 compared to $5.22 for the same period of 2020 primarily due to 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 as a result of our horizontal drilling programvolumes.
Production and 1,191 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
Ad Valorem Taxes.For the year ended December 31, 2016, oil revenues of $1782021, production and ad valorem taxes increased 60% to $100.2 million increased $52.5 million, or 42%, compared to revenues of $125$62.6 million for the same period of 2015. The2020, which is primarily related to an 88% increase in oil revenue was primarily attributable to a 53% increase intotal revenues which increased production offset by an 8% decrease in the average realized sales price, which fell to $41.51 per Bbl from $44.88 per Bbl.taxes. The increase in production was comprisedimpact of 1,182 MBbls attributable to wells placed on production as a result of our horizontal drilling program and 547 MBbls attributable to producing wells added from our acquired properties. Offsetting these increases were normal and expected declines from our existing wells.
| Twelve Months Ended December 31, | ||||||||||||||||||||||||||||||
| Per | Per | Total Change | BOE Change | |||||||||||||||||||||||||||
| (in thousands, except per unit amounts) | 2017 | BOE | 2016 | BOE | $ | % | $ | % | ||||||||||||||||||||||
| Lease operating expenses | $ | 49,907 | $ | 5.96 | $ | 38,353 | $ | 6.88 | $ | 11,554 | 30 | % | $ | (0.92 | ) | (13 | )% | |||||||||||||
| Production taxes | 22,396 | $ | 2.67 | 11,870 | $ | 2.13 | 10,526 | 89 | % | 0.54 | 25 | % | ||||||||||||||||||
| Depreciation, depletion and amortization | 115,714 | $ | 13.82 | 71,369 | $ | 12.81 | 44,345 | 62 | % | 1.01 | 8 | % | ||||||||||||||||||
| General and administrative | 27,067 | $ | 3.23 | 26,317 | $ | 4.72 | 750 | 3 | % | (1.49 | ) | (32 | )% | |||||||||||||||||
| Settled share-based awards | 6,351 | nm | — | nm | 6,351 | nm | nm | nm | ||||||||||||||||||||||
| Accretion expense | 677 | $ | 0.08 | 958 | $ | 0.17 | (281 | ) | (29 | )% | (0.09 | ) | (53 | )% | ||||||||||||||||
| Write-down of oil and natural gas properties | — | nm | 95,788 | nm | (95,788 | ) | nm | nm | nm | |||||||||||||||||||||
| Acquisition expense | 2,916 | nm | 3,673 | nm | (757 | ) | nm | nm | nm | |||||||||||||||||||||
| Twelve Months Ended December 31, | ||||||||||||||||||||||||||||||
| Per | Per | Total Change | BOE Change | |||||||||||||||||||||||||||
| (in thousands, except per unit amounts) | 2016 | BOE | 2015 | BOE | $ | % | $ | % | ||||||||||||||||||||||
| Lease operating expenses | $ | 38,353 | $ | 6.88 | $ | 27,036 | $ | 7.71 | $ | 11,317 | 42 | % | $ | (0.83 | ) | (11 | )% | |||||||||||||
| Production taxes | 11,870 | $ | 2.13 | 9,793 | $ | 2.79 | 2,077 | 21 | % | (0.66 | ) | (24 | )% | |||||||||||||||||
| Depreciation, depletion and amortization | 71,369 | $ | 12.81 | 69,249 | $ | 19.74 | 2,120 | 3 | % | (6.93 | ) | (35 | )% | |||||||||||||||||
| General and administrative | 26,317 | $ | 4.72 | 28,347 | $ | 8.08 | (2,030 | ) | (7 | )% | (3.36 | ) | (42 | )% | ||||||||||||||||
| Accretion expense | 958 | $ | 0.17 | 660 | $ | 0.19 | 298 | 45 | % | (0.02 | ) | (11 | )% | |||||||||||||||||
| Write-down of oil and natural gas properties | 95,788 | nm | 208,435 | nm | (112,647 | ) | nm | nm | nm | |||||||||||||||||||||
| Rig termination fee | — | nm | 3,075 | nm | (3,075 | ) | nm | nm | nm | |||||||||||||||||||||
| Acquisition expense | 3,673 | nm | 27 | nm | 3,646 | nm | nm | nm | ||||||||||||||||||||||
47
Depreciation, Depletion and Amortization (“DD&A”). The following table sets forth the components of our increased estimated proved reserves as a result of additions made through our horizontal drilling effortsdepreciation, depletion and acquisitions.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, 2016,2021, DD&A increased 3%decreased to $71.4$356.6 million from $69.2$480.6 million compared to the same period of 2015. The increase is primarily attributable to a 59% increase in production, offset by a 35% decrease in our per BOE DD&A rate. The increase in production was primarily attributable to an increased number of producing wells from our horizontal drilling program and acquisitions. For the year ended December 31, 2016, DD&A on a per unit basis decreased to $12.81 per BOE compared to $19.74 per BOE for the same period of 2015.2020. The decrease is attributable to our increased estimated proved reserves relative to our depreciable basein DD&A was primarily the result of the impairments of evaluated oil and assumed future development costs related to undeveloped proved reservesgas properties that were recognized during 2020 as well as a resultproduction decrease of additions made through our horizontal drilling efforts and acquisitions, offset by the write-down of oil and natural gas properties in the first half of 2016.6% as discussed above.
General and administrative, netAdministrative, Net of amounts capitalizedAmounts Capitalized (“G&A”). These are costs incurred for overhead, including payroll and benefits for our corporate staff, severance and early retirement expenses, costs of maintaining offices, managing our production and development operations, franchise taxes, depreciation of corporate level assets, public company costs, vesting of equity and liability awards under share-based compensation plans and related mark-to-market valuation adjustments over time, fees for audit and other professional services, and legal compliance.
G&A for the year ended December 31, 20172021 increased to $27.1$50.5 million compared to $26.3$37.2 million for the same period of 2016. G&A expenses for2020, 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 indicated include the following (in thousands):as well as higher compensation costs.
| Twelve Months Ended December 31, | |||||||||||||||
| 2017 | 2016 | $ Change | % Change | ||||||||||||
| Recurring expenses | |||||||||||||||
| G&A | $ | 21,554 | $ | 16,477 | $ | 5,077 | 31 | % | |||||||
| Share-based compensation | 4,287 | 2,735 | 1,552 | 57 | % | ||||||||||
| Fair value adjustments of cash-settled RSU awards | 701 | 6,881 | (6,180 | ) | (90 | )% | |||||||||
| Non-recurring expenses | |||||||||||||||
| Early retirement expenses | 444 | — | 444 | 100 | % | ||||||||||
| Early retirement expenses related to share-based compensation | 81 | — | 81 | 100 | % | ||||||||||
| Expense related to a threatened proxy contest | — | 224 | (224 | ) | (100 | )% | |||||||||
| Total G&A expenses | $ | 27,067 | $ | 26,317 | $ | 750 | 3 | % | |||||||
| Twelve Months Ended December 31, | |||||||||||||||
| 2016 | 2015 | $ Change | % Change | ||||||||||||
| Recurring expenses | |||||||||||||||
| G&A | $ | 16,477 | $ | 15,086 | $ | 1,391 | 9 | % | |||||||
| Share-based compensation | 2,735 | 2,068 | 667 | 32 | % | ||||||||||
| Fair value adjustments of cash-settled RSU awards | 6,881 | 6,084 | 797 | 13 | % | ||||||||||
| Non-recurring expenses | |||||||||||||||
| Early retirement expenses | — | 3,553 | (3,553 | ) | (100 | )% | |||||||||
| Early retirement expenses related to share-based compensation | — | 1,115 | (1,115 | ) | (100 | )% | |||||||||
| Expense related to a threatened proxy contest | 224 | 441 | (217 | ) | (49 | )% | |||||||||
| Total G&A expenses | $ | 26,317 | $ | 28,347 | $ | (2,030 | ) | (7 | )% | ||||||
Merger, Integration and Transaction Expenses. For the year ended December 31, 2021, we incurred merger, integration and transaction expenses of $14.3 million, which were associated with the Primexx Acquisition, as compared to the same period of 2016. Accretion expense generally correlates with the Company’s ARO,$28.5 million for 2020, which was $6.0 million at December 31, 2017 versus $6.7 million at December 31, 2016. See Note 12 in the Footnoteswere related to the Carrizo Acquisition. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the Company’s ARO.
Carrizo Acquisition.
Other Income and Expenses and Preferred Stock Dividends
| For the Year Ended December 31, | |||||||||||||||
| (in thousands) | 2017 | 2016 | $ Change | % Change | |||||||||||
| Interest expense, net of capitalized amounts | $ | 2,159 | $ | 11,871 | $ | (9,712 | ) | (82 | )% | ||||||
| Loss on early extinguishment of debt | — | 12,883 | (12,883 | ) | nm | ||||||||||
| Loss on derivative contracts | 18,901 | 20,233 | (1,332 | ) | (7 | )% | |||||||||
| Other income | (1,311 | ) | (637 | ) | (674 | ) | 106 | % | |||||||
| Total | $ | 19,749 | $ | 44,350 | |||||||||||
| Income tax (benefit) expense | $ | 1,273 | $ | (14 | ) | $ | 1,287 | (9,193 | )% | ||||||
| Preferred stock dividends | (7,295 | ) | (7,295 | ) | — | — | % | ||||||||
| For the Year Ended December 31, | |||||||||||||||
| (in thousands) | 2016 | 2015 | $ Change | % Change | |||||||||||
| Interest expense, net of capitalized amounts | $ | 11,871 | $ | 21,111 | $ | (9,240 | ) | (44 | )% | ||||||
| Loss on early extinguishment of debt | 12,883 | — | 12,883 | nm | |||||||||||
| (Gain) loss on derivative contracts | 20,233 | (28,358 | ) | 48,591 | (171 | )% | |||||||||
| Other income | (637 | ) | (198 | ) | (439 | ) | 222 | % | |||||||
| Total | $ | 44,350 | $ | (7,445 | ) | ||||||||||
| Income tax (benefit) expense | $ | (14 | ) | $ | 38,474 | $ | (38,488 | ) | (100 | )% | |||||
| Preferred stock dividends | (7,295 | ) | (7,895 | ) | 600 | (8 | )% | ||||||||
Interest expense, netExpense, Net of capitalized amounts. We finance a portionCapitalized Amounts. The 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, we 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, 2016 decreased $9.22021 increased $7.7 million to $11.9$102.0 million compared to $21.1$94.3 million for the same period of 2015.2020. The decreaseincrease is primarily attributabledue 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 $9.4 millionresult 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 comparedinterest.
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(Gain)Losson Derivative Contracts. The net (gain) loss on derivative contracts for the periods indicated includes the following:
| 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.
(Gain) Losson Extinguishment of Debt. During November 2021, in connection with the 2015 period, resulting fromexchange of $197.0 million of our Second Lien Notes for 5.5 million shares of our common stock, we recorded a higher average unevaluated property balanceloss on extinguishment of debt of $43.4 million, which consisted of the notional amount of common stock issued less the aggregate principal amount of the Second Lien Notes exchanged, net of a pro-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 extinguishment of debt of $2.4 million, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes.
During November 2020, in connection with the exchange of $389.0 million of our Senior Unsecured Notes for the Second Lien Notes, we recorded a gain on extinguishment of debt of $170.4 million, which consisted of the 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.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.
Income Tax Expense. We recorded income tax expense of $0.2 million for the year ended December 31, 2016 as2021 compared to $122.1 million for the same period of 2015. The increase in unevaluated property was primarily due to acquired properties (see Note 3 in2020. Since the Footnotes to the Financial Statements for information about the Company’s acquisitions). Offsetting the decrease was a $0.2 million increase in interest expense related to our debt due to a higher average debt balance for the year ended December 31, 2016 as compared to the same periodsecond quarter of 2015, resulting from the issuance of our 6.125% Senior Notes in November 2016 (see Note 5 in the Footnotes to the Financial Statements for additional information about the Company’s 6.125% Senior Notes).
| For the Year Ended December 31, | ||||||||||||
| | 2017 | 2016 | Change | |||||||||
| Oil derivatives | ||||||||||||
| Net gain (loss) on settlements | $ | (9,067 | ) | $ | 17,801 | $ | (26,900 | ) | ||||
| Net loss on fair value adjustments | (11,426 | ) | (37,543 | ) | 26,100 | |||||||
| Total loss on oil derivatives | $ | (20,493 | ) | $ | (19,742 | ) | $ | (800 | ) | |||
| Natural gas derivatives | ||||||||||||
| Net gain on settlements | $ | 594 | $ | 102 | $ | 500 | ||||||
| Net gain (loss) on fair value adjustments | 998 | (593 | ) | 1,600 | ||||||||
| Total gain (loss) on natural gas derivatives | $ | 1,592 | $ | (491 | ) | $ | 2,100 | |||||
| | ||||||||||||
| Total loss on oil & natural gas derivatives | $ | (18,901 | ) | $ | (20,233 | ) | $ | 1,300 | ||||
| For the Year Ended December 31, | ||||||||||||
| 2016 | 2015 | Change | ||||||||||
| Oil derivatives | ||||||||||||
| Net gain on settlements | $ | 17,801 | $ | 33,299 | $ | (15,500 | ) | |||||
| Net loss on fair value adjustments | (37,543 | ) | (5,403 | ) | (32,100 | ) | ||||||
| Total gain (loss) on oil derivatives | $ | (19,742 | ) | $ | 27,896 | $ | (47,600 | ) | ||||
| Natural gas derivatives | ||||||||||||
| Net gain on settlements | $ | 102 | $ | 1,717 | $ | (1,600 | ) | |||||
| Net loss on fair value adjustments | (593 | ) | (1,255 | ) | 600 | |||||||
| Total gain (loss) on natural gas derivatives | $ | (491 | ) | $ | 462 | $ | (1,000 | ) | ||||
| | ||||||||||||
| Total gain (loss) on oil & natural gas derivatives | $ | (20,233 | ) | $ | 28,358 | $ | (48,600 | ) | ||||
Liquidity and Capital Resources
2022 Capital Budget and Funding Strategy. Our 2022 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 expenditures. 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 Company hadfollowing 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 income tax expenseaccrual 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 foreseeable future thereafter. Our future capital requirements, both near-term and long-term, will depend on many factors, including, but not limited to, commodity prices, market conditions, our available liquidity and financing, acquisitions and divestitures of $1.3oil and gas properties, the availability of drilling rigs and completion crews, the cost of completion services, success of drilling programs, land and industry partner issues, weather delays, the acquisition
49
of leases with drilling commitments, and other factors. 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, 20172021, cash and cash equivalents decreased $10.3 million to $9.9 million compared to an income tax benefit of less than $0.1$20.2 million at December 31, 2020.
| Years Ended December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Net cash provided by operating activities | $974,143 | $559,775 | |||||||||
| Net cash used in investing activities | (876,400) | (529,883) | |||||||||
| Net cash used in financing activities | (108,097) | (22,997) | |||||||||
| Net change in cash and cash equivalents | ($10,354) | $6,895 | |||||||||
Operating Activities. Net cash provided by operating activities was $974.1 million and $559.8 million for the same period of 2016.years ended December 31, 2021 and 2020, respectively. The changeincrease in income tax isoperating activities was primarily attributable to the following:
•An increase in revenue due to an increase in realized pricing; and
•Changes related to deferred state income tax expense.timing of working capital payments and receipts; offset by
•Increase in cash paid for commodity derivative settlements.
Investing Activities. Net cash used in investing activities was $876.4 million and $529.9 million for the years ended December 31, 2021 and 2020, respectively. The effective tax rate differed fromincrease in investing activities was primarily attributable to the federal income tax rate of 35% primarilyfollowing:
•A $480.8 million increase in acquisitions due to the valuation allowance for the comparative periods, the effect of state taxes, and non-deductible executive compensation expenses.Primexx acquisition; offset by
•A decrease in capital expenditures.
•Redemption of $38.5the 6.25% Senior Notes in July 2021; and
•Repayments on the Credit Facility; offset by
•The issuance of $650.0 million forof 8.00% Senior Notes in July 2021
Credit Facility. As of December 31, 2021, our Credit Facility had a maximum credit amount of $5.0 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 same periodcredit agreement is subject to regular redeterminations in the spring and fall of 2015. The changeeach year, as well as special redeterminations described in income tax is primarily related to recording a valuation allowance of $108.8the credit agreement, which in 2015 and the difference ineach case may reduce the amount of income (loss) before income taxes between periods.the borrowing base. On November 1, 2021, we entered into the fifth amendment to our credit agreement governing the Credit Facility which, among other things, reaffirmed the borrowing base and elected commitment amount of $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 maintenance of certain 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.
50
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 Second Lien Notes, for a notional amount of approximately $223.1 million of our common stock, which equated to 5.5 million shares.
8.00% 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 a private placement for proceeds of approximately $638.1 million, net of underwriting discounts and commissions and offering costs. The effective tax rate8.00% 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 0% in 2016 and (19)% in 2015 differedour outstanding 6.25% Senior Notes due 2023, which became redeemable on July 21, 2021. We used a portion of the net proceeds from the federal income tax rate8.00% Senior Notes to redeem all of 35% primarily dueour outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the valuation allowanceCredit Facility.
See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information on our long-term debt.
Material Cash Requirements
As of December 31, 2021, we have financial obligations associated with our outstanding long-term debt, including interest payments and principal repayments. See “Note 7 – Borrowings” of the comparative periods,Notes to our Consolidated Financial Statements for further discussion of the effectcontractual commitments under our debt agreements, including the timing of state taxes,principal repayments. Additionally, we have operational obligations associated with long-term, non-cancelable leases, drilling rig contracts, frac service contracts, gathering, processing and non-deductible executive compensation expenses.transportation service agreements, and estimates of future asset retirement obligations. See “Note 14 – Asset Retirement Obligations” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional details.
We estimate that the combination of our sources of capital, as discussed above, will continue to be adequate to fund our short- and long-term contractual obligations.
Other Commitments
The following table includes our current oil sales contracts and firm transportation agreements as of December 31, 2021:
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 | |||||||||||||||||||||||||||
(2)Each of the firm transportation agreements shown in the table above grant us access to delivery points in several locations along the Gulf Coast.
(3)The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
| | For the Year Ended December 31, | ||||||||
| Components of income tax rate reconciliation | 2017 | 2016 | 2015 | ||||||
| Income tax expense computed at the statutory federal income tax rate | 35 | % | 35 | % | 35 | % | |||
| State taxes net of federal benefit | 1 | % | — | % | 1 | % | |||
| Restricted stock and stock options | — | % | —% | —% | |||||
| Section 162(m) | — | % | (1 | )% | (1 | )% | |||
| Valuation allowance | (35 | )% | (34 | )% | (54 | )% | |||
| Effective income tax rate | 1 | % | — | % | (19 | )% | |||
Critical Accounting Estimates
For additional information,discussion regarding our significant accounting policies, see Note 11 in the Footnotes to the Financial Statements.
“Note 2 – Summary of Significant Accounting Policies and Critical AccountingPolicies” of the Notes to our Consolidated Financial Statements.
Use of Estimates
51
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 instruments) plus the lowerassets and liabilities, fair values of cost orcontingent consideration arrangements, grant date fair value of unevaluatedstock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.
Oil and Natural 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.
Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method whereby the 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 depletion 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. Each quarter, a full cost ceiling test is performed to determine whether an impairment to our evaluated oil and gas properties should be recorded.
The estimated future net revenues used in the net capitalized costscost center ceiling are calculated using the 12-Month Average Realized Price of provedoil, 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 natural gas properties net of related deferred taxes. The Company refers to this comparison as a “ceiling test.” If the net capitalized costs of proved oil and natural gas properties exceed the estimated discounted (at a 10% annualized rate) future net cash flows from
| 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 | $53.90 | ||||||||||||||||||||||||||
| Percent increase (decrease) in 12-Month Average Realized Price | 75 | % | (31 | %) | (8 | %) | |||||||||||||||||||||||
The table below presents the cumulative results of the full cost ceiling test along with various pricing scenarios to demonstrate the sensitivity of our full cost ceiling and estimated total proved reserve volumes to changes in 12-month average oil and natural gas prices on closing prices on the first day of each month. This sensitivity analysis is as of December 31, 2017 and, accordingly, does not consider drilling results, production, changes in oil and natural gas prices, and changes in future development and operating costs subsequent to December 31, 2017 that may require revisions to our proved reserve estimates and resulting estimated future net cash flows used in the full cost ceiling test. The volumes resulting from the sensitivity analysis, which are for illustrative purposes only, incorporate a number of assumptions and have not been audited by the Company’s third-party engineer.
| 12-Month Average Prices | Excess (Deficit) of Full Cost Ceiling Over Net Capitalized Costs | ||||||||||
| Pricing Scenarios | Oil ($/Bbl) | Natural gas ($/Mcf) | (in thousands) | ||||||||
| December 31, 2017 Actual | $ | 51.34 | $ | 2.98 | 241,000 | ||||||
| Combined price sensitivity | |||||||||||
| Oil and natural gas +10% | $ | 56.47 | $ | 3.28 | 501,507 | ||||||
| Oil and natural gas -10% | 46.21 | 2.68 | (18,719 | ) | |||||||
| Oil price sensitivity | |||||||||||
| Oil +10% | $ | 56.47 | $ | 2.98 | 478,728 | ||||||
| Oil -10% | 46.21 | 2.98 | 4,060 | ||||||||
| Natural gas sensitivity | |||||||||||
| Natural gas +10% | $ | 51.34 | $ | 3.28 | 264,174 | ||||||
| Natural gas -10% | 51.34 | 2.68 | 218,615 | ||||||||
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| 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
We 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 cash or futures index price.
Our financial condition and 7results of operations can be significantly impacted by changes in the Footnotes tomarket value of our derivative instruments as a result of the Financial Statementsvolatility of oil and Partgas prices. See “Part II, Item 7A7A. Quantitative and Qualitative Disclosures about Market Risk - Commodity Price Risk.
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 taxes
Taxes
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 determinationAs of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company hadDecember 31, 2021, a valuation allowance continues to be in place which reduces the net deferred tax assets to zero.
53
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 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 $60.9 million as of December 31, 2017. See Note 11 in the FootnotesNotes to theour Consolidated Financial Statements for additional information regarding Income Taxes.discussion.
Our ability to utilize our federal net operating losses (“NOLs”) to reduce future taxable income 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 (“ASU”)
Pronouncements
See Note“Note 2 in- Summary of Significant Accounting Policies” of the FootnotesNotes to theour Consolidated Financial Statements for information regarding ASUs.discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board.
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 Risk
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, in addition to modification of our capital spending plans related to operational activities and acquisitions.prices.
54
The following 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 riskRate Risk
Counterparty and customer credit riskCustomer Credit Risk
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, 2017 ourWe generally have the right to withhold future revenue distributions to recover past due receivables from joint interest receivables were approximately $42.7 million.owners.
ITEM 8. Financial Statements and Supplementary Data
| Page | |||||
| Reports of Independent Registered Public Accounting | |||||
| Consolidated Balance Sheets as of December 31, | |||||
| Consolidated Statements of Operations for | |||||
| Consolidated Statements of Stockholders’ Equity for | |||||
| Consolidated Statements of Cash Flows for | |||||
| Notes to Consolidated Financial Statements | |||||
REPORT 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 Inc. (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 20172021 and 2016,2020, the related consolidated statements of operations, shareholders’stockholders’ equity, and cash flows for each of the twothree years in the period ended December 31, 2017,2021, and the related notes (collectively referred to as the “financial statements”). In our opinion, thefinancial statements present fairly, in all material respects, the financial position of the Company as of December 31, 20172021 and 2016,2020, and the results of its operations and its cash flows for each of the twothree years in the period ended December 31, 2017,2021, 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, 2017,2021, based on criteria established in the 2013 Internal Control-IntegratedControl—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 27, 201824, 2022 expressed an unqualified opinion.
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 matters
The 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.
The 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 accounting
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 necessary to estimate the volumes 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.
57
•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 historical pricing differentials, operating costs, estimated development 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:
◦We compared the estimated pricing differentials used in the reserve report to prices realized by the Company related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials
◦We tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs
◦We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells to ascertain its reasonableness
◦We tested the working and net revenue interests used in the reserve report by inspecting land and division order records
◦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 and intent to develop the proved undeveloped properties, and
◦We applied analytical procedures to production forecasts in the reserve report by comparing to historical actual results and to the prior year reserve report.
Estimate of the fair value of oil and gas properties and related proved and unproved reserves associated with the Primexx Acquisition
As described further in Note 4 to the financial statements, the Company acquired certain producing oil & natural gas assets and undeveloped acreage from Primexx Resource Development, LLC and BPP Acquisition, LLC (collectively, “Primexx,” the “Primexx Acquisition”), which required management to make estimates of the fair value associated with proved and unproved reserves and related discounted net cash flows. To estimate the volumes of proved and unproved reserves and the associated discounted net cash flows, management makes significant estimates and assumptions including forecasting the production decline rate of proved 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 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 necessary to estimate the volume and future discounted 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 audit 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 fair 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 judgements 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 seller provided information, including, but not limited to historical pricing differentials, operating costs, estimated development costs, and ownership
58
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:
◦We compared the estimated pricing differentials used in the reserve report to historical prices realized by Primexx
◦We tested models used to estimate the future operating costs in the acquisition reserve report and compared amounts to historical operating costs
◦We evaluated the method used to determine estimated future development costs used in the reserve report and compared management’s estimate to amounts expended for recently drilled and completed wells
◦We tested the working and net revenue interests used in the reserve report by inspecting land and division order records
◦We evaluated the risk adjustments applied to proved and unproved reserve volumes by comparing against industry accepted factors
◦We evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report examining historical conversion rates and support for the Company’s ability and intent to develop the proved undeveloped and unproved properties; and
◦We applied analytical procedures to production forecasts in the reserve report 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 27, 201824, 2022
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
Callon Petroleum Company
Opinion on internal control over financial reporting
We have audited the accompanying consolidated statements of operations, stockholders’ equity and cash flowsinternal control over financial reporting of Callon Petroleum Company for the year ended(a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2015. These financial statements are2021, based on criteria established in the responsibility2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Company’s management. Our responsibility is to express anTreadway Commission (“COSO”). In our opinion, on thesethe Company maintained, in all material respects, effective internal control over financial statementsreporting as of December 31, 2021, based on our audit.criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.
We conducted our auditalso 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, 2021, and our report dated February 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. 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 financial statements are freerisk that a material weakness exists, testing and evaluating the design and operating effectiveness of material misstatement. An audit includes examining,internal control based on a test basis, evidence supporting the amountsassessed risk, and disclosuresperforming such other procedures as we considered necessary in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.circumstances. We believe that our audit provides a reasonable basis for our opinion.
Definition and limitations of internal control over financial reporting
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/Ernst & Young GRANT THORNTON LLP
Callon Petroleum Company
Consolidated Balance Sheets
(inIn thousands, except par and per 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, 2017 | December 31, 2016 | ||||||
| ASSETS | |||||||
| Current assets: | |||||||
| Cash and cash equivalents | $ | 27,995 | $ | 652,993 | |||
| Accounts receivable | 114,320 | 69,783 | |||||
| Fair value of derivatives | 406 | 103 | |||||
| Other current assets | 2,139 | 2,247 | |||||
| Total current assets | 144,860 | 725,126 | |||||
| Oil and natural gas properties, full cost accounting method: | |||||||
| Evaluated properties | 3,429,570 | 2,754,353 | |||||
| Less accumulated depreciation, depletion, amortization and impairment | (2,084,095 | ) | (1,947,673 | ) | |||
| Net evaluated oil and natural gas properties | 1,345,475 | 806,680 | |||||
| Unevaluated properties | 1,168,016 | 668,721 | |||||
| Total oil and natural gas properties, net | 2,513,491 | 1,475,401 | |||||
| Other property and equipment, net | 20,361 | 14,114 | |||||
| Restricted investments | 3,372 | 3,332 | |||||
| Deferred tax asset | 52 | — | |||||
| Deferred financing costs | 4,863 | 3,092 | |||||
| Acquisition deposit | 900 | 46,138 | |||||
| Other assets, net | 5,397 | 384 | |||||
| Total assets | $ | 2,693,296 | $ | 2,267,587 | |||
| LIABILITIES AND STOCKHOLDERS’ EQUITY | |||||||
| Current liabilities: | |||||||
| Accounts payable and accrued liabilities | $ | 162,878 | $ | 95,577 | |||
| Accrued interest | 9,235 | 6,057 | |||||
| Cash-settleable restricted stock unit awards | 4,621 | 8,919 | |||||
| Asset retirement obligations | 1,295 | 2,729 | |||||
| Fair value of derivatives | 27,744 | 18,268 | |||||
| Total current liabilities | 205,773 | 131,550 | |||||
| Senior secured revolving credit facility | 25,000 | — | |||||
| 6.125% senior unsecured notes due 2024, net of unamortized deferred financing costs | 595,196 | 390,219 | |||||
| Asset retirement obligations | 4,725 | 3,932 | |||||
| Cash-settleable restricted stock unit awards | 3,490 | 8,071 | |||||
| Deferred tax liability | 1,457 | 90 | |||||
| Fair value of derivatives | 1,284 | 28 | |||||
| Other long-term liabilities | 405 | 295 | |||||
| Total liabilities | 837,330 | 534,185 | |||||
| Commitments and contingencies | |||||||
| Stockholders’ equity: | |||||||
| Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 1,458,948 shares outstanding | 15 | 15 | |||||
| Common stock, $0.01 par value, 300,000,000 shares authorized; 201,836,172 and 201,041,320 shares outstanding, respectively | 2,018 | 2,010 | |||||
| Capital in excess of par value | 2,181,359 | 2,171,514 | |||||
| Accumulated deficit | (327,426 | ) | (440,137 | ) | |||
| Total stockholders’ equity | 1,855,966 | 1,733,402 | |||||
| Total liabilities and stockholders’ equity | $ | 2,693,296 | $ | 2,267,587 | |||
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Operations
(inIn 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, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Operating revenues: | |||||||||||
| Oil sales | $ | 322,374 | $ | 177,652 | $ | 125,166 | |||||
| Natural gas sales | 44,100 | 23,199 | 12,346 | ||||||||
| Total operating revenues | 366,474 | 200,851 | 137,512 | ||||||||
| Operating expenses: | |||||||||||
| Lease operating expenses | 49,907 | 38,353 | 27,036 | ||||||||
| Production taxes | 22,396 | 11,870 | 9,793 | ||||||||
| Depreciation, depletion and amortization | 115,714 | 71,369 | 69,249 | ||||||||
| General and administrative | 27,067 | 26,317 | 28,347 | ||||||||
| Settled share-based awards | 6,351 | — | — | ||||||||
| Accretion expense | 677 | 958 | 660 | ||||||||
| Write-down of oil and natural gas properties | — | 95,788 | 208,435 | ||||||||
| Rig termination fee | — | — | 3,075 | ||||||||
| Acquisition expense | 2,916 | 3,673 | 27 | ||||||||
| Total operating expenses | 225,028 | 248,328 | 346,622 | ||||||||
| Income (loss) from operations | 141,446 | (47,477 | ) | (209,110 | ) | ||||||
| Other (income) expenses: | |||||||||||
| Interest expense, net of capitalized amounts | 2,159 | 11,871 | 21,111 | ||||||||
| Loss on early extinguishment of debt | — | 12,883 | — | ||||||||
| (Gain) loss on derivative contracts | 18,901 | 20,233 | (28,358 | ) | |||||||
| Other income | (1,311 | ) | (637 | ) | (198 | ) | |||||
| Total other (income) expense | 19,749 | 44,350 | (7,445 | ) | |||||||
| Income (loss) before income taxes | 121,697 | (91,827 | ) | (201,665 | ) | ||||||
| Income tax (benefit) expense | 1,273 | (14 | ) | 38,474 | |||||||
| Net income (loss) | 120,424 | (91,813 | ) | (240,139 | ) | ||||||
| Preferred stock dividends | (7,295 | ) | (7,295 | ) | (7,895 | ) | |||||
| Income (loss) available to common stockholders | $ | 113,129 | $ | (99,108 | ) | $ | (248,034 | ) | |||
| Income (loss) per common share: | |||||||||||
| Basic | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | |||
| Diluted | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | |||
| | |||||||||||
| Shares used in computing income (loss) per common share: | |||||||||||
| Basic | 201,526 | 126,258 | 65,708 | ||||||||
| Diluted | 202,102 | 126,258 | 65,708 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Stockholders’ Equity
(inIn 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 | ||||||||||||||||||||||||||||||||||
| Preferred Stock | Common Stock | Capital in Excess of Par | Retained Earnings (Deficit) | Total Stockholders' Equity | |||||||||||||||
| Balance at 12/31/2014 | $ | 16 | $ | 552 | $ | 526,162 | $ | (92,995 | ) | $ | 433,735 | ||||||||
| Net loss | — | — | — | (240,139 | ) | (240,139 | ) | ||||||||||||
| Shares issued pursuant to employee benefit plans | — | — | 268 | — | 268 | ||||||||||||||
| Restricted stock | — | 8 | 1,323 | — | 1,331 | ||||||||||||||
| Common stock issued | — | 241 | 175,217 | — | 175,458 | ||||||||||||||
| Preferred stock dividend | — | — | — | (7,895 | ) | (7,895 | ) | ||||||||||||
| Balance at 12/31/2015 | $ | 16 | $ | 801 | $ | 702,970 | $ | (341,029 | ) | $ | 362,758 | ||||||||
| Net loss | — | — | — | (91,813 | ) | (91,813 | ) | ||||||||||||
| Shares issued pursuant to employee benefit plans | — | — | 275 | — | 275 | ||||||||||||||
| Restricted stock | — | 4 | 2,323 | — | 2,327 | ||||||||||||||
| Common stock issued | — | 1,198 | 1,465,952 | — | 1,467,150 | ||||||||||||||
| Preferred stock conversion | (1 | ) | 7 | (6 | ) | — | — | ||||||||||||
| Preferred stock dividend | — | — | — | (7,295 | ) | (7,295 | ) | ||||||||||||
| Balance at 12/31/2016 | $ | 15 | $ | 2,010 | $ | 2,171,514 | $ | (440,137 | ) | $ | 1,733,402 | ||||||||
| Net income | — | — | — | 120,424 | 120,424 | ||||||||||||||
| Shares issued pursuant to employee benefit plans | — | — | 311 | — | 311 | ||||||||||||||
| Restricted stock | — | 8 | 9,098 | — | 9,106 | ||||||||||||||
| Common stock issued | — | — | 18 | — | 18 | ||||||||||||||
Impact of forfeiture estimate (a) | — | — | 418 | (418 | ) | — | |||||||||||||
| Preferred stock dividend | — | — | — | (7,295 | ) | (7,295 | ) | ||||||||||||
| Balance at 12/31/2017 | $ | 15 | $ | 2,018 | $ | 2,181,359 | $ | (327,426 | ) | $ | 1,855,966 | ||||||||
The accompanying notes are an integral part of these consolidated financial statements.
Callon Petroleum Company
Consolidated Statements of Cash Flows
(inIn 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 | ||||||||||||||
| For the Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | |||||||||
| Cash flows from operating activities: | |||||||||||
| Net income (loss) | $ | 120,424 | $ | (91,813 | ) | $ | (240,139 | ) | |||
| Adjustments to reconcile net income to cash provided by operating activities: | |||||||||||
| Depreciation, depletion and amortization | 118,051 | 73,072 | 69,891 | ||||||||
| Write-down of oil and natural gas properties | — | 95,788 | 208,435 | ||||||||
| Accretion expense | 677 | 958 | 660 | ||||||||
| Amortization of non-cash debt related items | 2,150 | 3,115 | 3,123 | ||||||||
| Deferred income tax (benefit) expense | 1,273 | (14 | ) | 38,474 | |||||||
| Loss on derivatives, net of settlements | 10,429 | 38,135 | 6,658 | ||||||||
| Loss on sale of other property and equipment | 62 | — | — | ||||||||
| Non-cash loss on early extinguishment of debt | — | 9,883 | — | ||||||||
| Non-cash expense related to equity share-based awards | 8,254 | 2,765 | 2,688 | ||||||||
| Change in the fair value of liability share-based awards | 3,288 | 6,953 | 6,612 | ||||||||
| Payments to settle asset retirement obligations | (2,047 | ) | (1,471 | ) | (3,258 | ) | |||||
| Changes in current assets and liabilities: | |||||||||||
| Accounts receivable | (44,495 | ) | (30,055 | ) | (4,761 | ) | |||||
| Other current assets | 108 | (786 | ) | (20 | ) | ||||||
| Current liabilities | 30,947 | 25,288 | 8,001 | ||||||||
| Other long-term liabilities | 121 | 96 | 80 | ||||||||
| Long-term prepaid | (4,650 | ) | — | — | |||||||
| Other assets, net | (1,528 | ) | (840 | ) | 338 | ||||||
| Payments for cash-settled restricted stock unit awards related to early retirements related to early retirements | — | — | (3,538 | ) | |||||||
| Payments for cash-settled restricted stock unit awards | (13,173 | ) | (10,300 | ) | (3,925 | ) | |||||
| Net cash provided by operating activities | 229,891 | 120,774 | 89,319 | ||||||||
| Cash flows from investing activities: | |||||||||||
| Capital expenditures | (419,839 | ) | (190,032 | ) | (227,292 | ) | |||||
| Acquisitions | (718,456 | ) | (654,679 | ) | (32,245 | ) | |||||
| Acquisition deposit | 45,238 | (46,138 | ) | — | |||||||
| Proceeds from sales of mineral interest and equipment | 20,525 | 24,562 | 377 | ||||||||
| Net cash used in investing activities | (1,072,532 | ) | (866,287 | ) | (259,160 | ) | |||||
| Cash flows from financing activities: | |||||||||||
| Borrowings on senior secured revolving credit facility | 25,000 | 217,000 | 181,000 | ||||||||
| Payments on senior secured revolving credit facility | — | (257,000 | ) | (176,000 | ) | ||||||
| Payments on term loans | — | (300,000 | ) | — | |||||||
| Issuance of 6.125% senior unsecured notes due 2024 | 200,000 | 400,000 | — | ||||||||
| Premium on the issuance of 6.125% senior unsecured notes due 2024 | 8,250 | — | — | ||||||||
| Payment of deferred financing costs | (7,194 | ) | (10,793 | ) | — | ||||||
| Issuance of common stock | — | 1,357,577 | 175,459 | ||||||||
| Payment of preferred stock dividends | (7,295 | ) | (7,295 | ) | (7,895 | ) | |||||
| Tax withholdings related to restricted stock units | (1,118 | ) | (2,207 | ) | (2,467 | ) | |||||
| Net cash provided by financing activities | 217,643 | 1,397,282 | 170,097 | ||||||||
| Net change in cash and cash equivalents | (624,998 | ) | 651,769 | 256 | |||||||
| Balance, beginning of period | 652,993 | 1,224 | 968 | ||||||||
| Balance, end of period | $ | 27,995 | $ | 652,993 | $ | 1,224 | |||||
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. | Acquisitions and Divestitures | 13. | |||||||||
| 5. | 14. | ||||||||||
| 6. | 15. | Accounts Receivable, Net | |||||||||
| 7. | 16. | ||||||||||
| 8. | 17. | ||||||||||
| 9. | 18. | ||||||||||
| 1. | 9. | ||
| 2. | 10. | ||
| 3. | 11. | ||
| 4. | 12. | ||
| 5. | 13. | ||
| 6. | 14. | ||
| 7. | 15. | ||
| 8. | |||
Note 1-– Description of Business and Basis of Presentation
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.
Note 2– Summaryof several prospective intervals, including multiple levels of the Wolfcamp formation and the Spraberry shales. Callon has assembled a multi-year inventory of potential horizontal well locations and intends to add to this inventory through delineation drilling of emerging zones on its existing acreage and acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.
Significant Accounting Policies
Basis of presentation
Principles of Consolidation
The Consolidated Financial Statementsconsolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. GAAP. The Company proportionately consolidates its subsidiary, Callon Petroleum Operatingundivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, (“CPOC”). CPOC alsoas a partner or member, has subsidiaries, namely Callon Offshore Production, Inc.undivided interests in the oil and Mississippi Marketing, Inc. All intercompany accounts and transactions have been eliminated.gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments, and all intercompany account and transaction eliminations, necessary to present fairly the Company’s financial position, the results of its operations and its cash flows for the periods indicated. Certain prior year amounts may 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 that affect thefor reported amounts of assets and liabilities, and 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 evaluated 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 an original maturitymaturities 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 credit losses and bad debt expense was immaterial for all periods presented.
65
Concentration of Credit Risk and Major Customers
The Company recognizes revenue underconcentration of accounts receivable from entities in the entitlements method of accounting. Under this method, revenue is deferred for deliveries in excess ofoil and gas industry may impact the Company’s net revenue interest, while revenue is accrued for the undelivered volumes.overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The revenue we receive from the sale of NGLs is included in natural gas sales. Natural gas balancing receivables and payables were immaterial as of December 31, 2017 and 2016.
| For the Year Ended December 31, | |||||||||
| 2017 | 2016 | 2015 | |||||||
| Plains Marketing, L.P. | 29 | % | 16 | % | 19 | % | |||
| Enterprise Crude Oil, LLC | 18 | % | 43 | % | 42 | % | |||
| Rio Energy International, Inc. | 17 | % | — | % | — | % | |||
| Shell Trading Company | 9 | % | 18 | % | 4 | % | |||
| Permian Transport and Trading | — | % | — | % | 15 | % | |||
| Other | 27 | % | 23 | % | 20 | % | |||
| Total | 100 | % | 100 | % | 100 | % | |||
| 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.
See “Note 8 - Derivative Instruments and Hedging Activities” for discussion of credit risk related with the Company’s commodity derivative counterparties.
Oil and Natural Gas Properties
When applicable, proceedsProceeds from the sale or dispositiondivestitures of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction toof evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs through adjustmentsand estimated proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2021, 2020 and 2019, the Company did not have any sales of oil and gas properties that significantly altered such relationship.
Historicalquarterly basis by dividing current quarter production by estimated proved oil and gas reserves at the beginning of the quarter then applying such depletion rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future development costs of oil and natural gas properties, which have been evaluated and containexpenditures to be incurred in developing proved reserves, as well as the historical costnet of properties that have been determined to have no future economic value, are depleted using the unit-of-production method based on proved reserves. estimated salvage values.
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 unevaluated properties and the weighted average interest rate of outstanding borrowings.
$95,788 write-downproperties, less related deferred income taxes, over the cost center ceiling is recognized as an impairment of evaluated oil and gas properties. An 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 natural gas properties, respectively, as a result of the ceiling test limitation. See Notes 2 and 13 for additional information regarding the Company’s oil and natural gas properties. less related deferred income taxes.
Upon the acquisition or discovery of oil and natural gas properties, the Company estimates the future net costs to dismantle, abandon and restore the property by using available geological, engineering and regulatory data. Such cost estimates are periodically updated for changes in conditions and requirements. In accordance with asset retirement obligation guidance, such costs are capitalized to the full cost pool when the related liabilities are incurred. In accordance with full cost accounting rules, assets recorded in connection with the recognition of an asset retirement obligation are included as part of the costs subject to the full cost ceiling limitation. The future cash outflows associated with settling the recorded asset retirement obligations are excluded from the computation of the present value of estimated future net revenues used in determining the full cost center ceiling amount.
is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years.The Company capitalizes interest on unevaluated oil and gas properties. Capitalized interest cannot exceed gross interest expense. During the years ended December 31, 2017, 2016 and 2015, the Company capitalized $33,783, $19,857 and $10,459 of interest expense.
DeferredFinancingCosts
ProvisionsRevenue Recognition
Stock Options. For stock options the Company expected, some of which are subject to settle in common stock, share-basedachievement of certain performance conditions. Share-based compensation expense was based onis recognized as “General and administrative expense” in the grant-date fair valueconsolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as calculated usingthey occur. See “Note 10 - Share-Based Compensation” for further details of the Black-Scholes option pricing modelawards discussed below.
RSUequityawards and Cash-settleableCash-Settled RSU awards. ForAwards. Share-based compensation expense for RSU equity awards that the Company expects to settle in common stock, share-based compensation expenseEquity Awards is based on the grant-date fair value and recognized straight-line over the vesting period (generally three years).years for employees and one year for non-employee directors) using the straight-line method. For RSU equity awardsEquity Awards with vesting terms subject to a marketperformance 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). For Cash-settleableCash-Settled RSU awardsAwards 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 is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, because vesting of these awards is subject to a market condition, 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”) are remeasured at fair value at the end of each reporting 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 five years, depending on the date of grant.See the Accounting Standards Updates section within this footnote for information about recently adopted ASUs related to Stock Compensation.
SupplementalCash Flow Information
The Company uses the full cost method of accounting for its explorationunder which all productive and development activities. Under this method of accounting, the cost of both successful and unsuccessfulnonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Such amounts include the cost of drilling and equipping productive wells, dry hole costs, lease acquisition costs, delay rentals, interest capitalized on unevaluated leases, other costs related to exploration and development activities, and site restoration, dismantlement and abandonment costs capitalized in accordance with asset retirement obligation accounting guidance. Costs capitalized also include any internalInternal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and benefits, but do not include anystock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production general corporate overhead orand similar activities.activities are expensed as incurred.
From time to accumulated depreciation, depletion, amortizationtime, the Company exchanges undeveloped acreage with third parties. The exchanges are recorded at fair value and impairmentthe 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 the salesuch adjustment would significantly alter the relationship between capitalized costs and proved reserves inof 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 caserepresents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a gain or loss is recognized.
Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties includingand related capitalized interest on such costs.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 unevaluated properties and the weighted average interest rate of outstanding borrowings.
Under full cost accounting rules, the Company reviews the carryingnet book value of its proved oil and natural gas properties each quarter. Under these rules, capitalized coststhe net book value of oil and natural gas properties, net of accumulated depreciation, depletion and amortization andless related deferred income taxes, may not exceedare limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net cash flowsrevenues from estimated proved oil and natural gas reserves, discounted atless estimated future expenditures to be incurred in developing and producing the estimated proved oil and gas reserves computed using a discount factor of 10%, plus (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties and (c) netincluded in the costs being amortized; less (ii) related income tax effects. Any excess of related tax effects (collectively called the full cost ceiling). These rules require pricing based on the preceding 12-months’ average oil and natural gas prices based on closing prices on the first day of each month and require a write-down if the net capitalized costs of proved oil and natural gas properties exceeds the full cost ceiling. At December 31, 2017 and 2016, the average realized prices used in determining the estimated future net cash flows from proved reserves were $51.34 and $42.75 per barrel of oil, respectively, and $2.98 and $2.48 per Mcf of natural gas, respectively. For the periods ended December 31, 2017 and 2016, the Company recognized no write-downbook value of oil and natural gas properties and a
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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 the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company depreciates its Other propertydid not recognize impairments of evaluated oil and equipment using the straight-line method over estimated useful lives of three to 20 years. Depreciation expense of $900, $793 and $865 relating to other property and equipment was included in general and administrative expenses in the Company’s consolidated statements of operationsgas properties for the years ended December 31, 2017, 20162021 and 2015, respectively. The accumulated depreciation on2019. 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.
Depreciation of other property and equipment was $16,259 and $15,227 as of December 31, 2017 and 2016, respectively. The Company reviews its Other property and equipment for impairment when indicators of impairment exist. See Note 14 for additional information.
is recognized using the straight-line method based on estimated useful lives ranging from two to twenty years.
DeferredFinancingCosts
Deferred financing costs associated with the Second Lien Notes and the Unsecured Senior Notes, both defined below, are stated at cost, net of amortization, andclassified as a direct reduction fromof the debt’srelated carrying value on the consolidated balance sheet. For revolving debt arrangements, deferredsheets and are amortized to interest expense using the effective interest method over the terms of the related debt. Deferred financing costs associated with the Credit Facility, as defined below, are stated at cost, net of amortization, as an asset onclassified in “Other long-term assets” in the consolidated balance sheet. Amortization of deferred financing costs is computedsheets and are amortized to interest expense using the straight-line method over the lifeterm of the loan. Amortization of deferred financing costs of $2,150, $3,115 and $3,123 were recorded for the years ended December 31, 2017, 2016 and 2015, respectively. facility.
Asset Retirement Obligations |
The Company is required to recordrecords 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 retirementsurface of tangible long-life assetsthe land in accordance with the terms of oil and the associatedgas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement costs. The Company estimatesobligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a risk-adjustedcredit-adjusted risk-free discount rate and an inflation factor in order to determine the current present value of the asset retirement obligation. Interest is accreted on theThe present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported as accretion expense within operating expensesin “Depreciation, depletion and amortization” in the Consolidated Statementsconsolidated statements of Operations.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.consolidated balance sheets. See Note 12“Note 14 - Asset Retirement Obligations” for additional information.
Derivative contracts outstandingInstruments
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 of December 31, 2017 were not designated as accounting hedges, and are carried on the balance sheeteither an asset or liability measured at fair value. ChangesThe 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 (“ISDA Agreements”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract.
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 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 contracts not designatedinstruments, as accounting hedgeswell as its contingent consideration arrangements, are reflected in earningsrecognized as a gain or“(Gain) loss on derivative contracts.contracts” in the consolidated statements of operations in the period in which the changes occur. See Notes 6“Note 8 - Derivative Instruments and 7Hedging Activities” and “Note 9 - Fair Value Measurements” for additional information regarding the Company’s derivative contracts.further discussion.
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The Company recognizes revenues from the sales of oil, 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.
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.
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. 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 include deferred taxes resulting primarily fromare recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences duebetween 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 different reporting methods for oil and natural gas properties for financial reporting purposes and income tax purposes.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 statutory depletion carryforwards and tax credit carryforwards. A valuation allowance is provided for that portionThe Company assesses the realizability of its deferred tax assets if any, for whichon a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is deemed more likely than not that itall or a portion of the deferred tax assets will not be realized. As of December 31, 2017 therealized and a valuation allowance was $60,919.is required. See Note 11“Note 12 - Income Taxes” for additional information.further discussion.
| Share-Based Compensation |
The Company grants to directors and employees stock options and restricted stock unit awards (“RSU awards”) that may be settled in common stock (“RSU equity awards”Equity Awards”) or cash (“Cash-settleableCash-Settled RSU awards”Awards”).
RSU Equity Awards and recognized straight-line over the vesting period (generally three years).
Cash SARs. Stock appreciation rights to be settled in cash (“Cash SARs”) are remeasured at fair value at the end of each reporting 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 five years, depending on the date of grant.
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SupplementalCash Flow Information
The following table sets forth the non-cash investing and supplemental cash flow information for the periods indicated:
| 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 | |||||||||||||||||
| For the Year Ended December 31, | ||||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Non-cash investing information | ||||||||||||
| Change in accrued capital expenditures | $ | (39,532 | ) | $ | (613 | ) | $ | (16,813 | ) | |||
Supplemental cash flow information (a) | ||||||||||||
| Cash paid for interest, net of capitalized interest | $ | — | $ | 8,679 | $ | 17,978 | ||||||
(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 EPS amounts have been computednet income (loss) attributable to common shareholders per common share is based on the weighted-averageweighted average number of shares of common stock outstanding for the period. Diluted EPS,net income (loss) attributable to common shareholders per common share is calculated using the treasury-stocktreasury stock method reflectsand is based on the potential dilution caused byweighted average number of common shares and all potentially dilutive common shares outstanding during the exerciseyear 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 optionsdiluted weighted average shares outstanding. See “Note 6 - Earnings Per Share” for further discussion.
Industry Segment and vestingGeographic Information
The Company operates in 1 industry segment, which is the exploration, development, and production of restricted stockcrude oil, natural gas, and RSUs settleableNGLs. All of the Company’s operations are located in shares.
the United States and currently all revenues are attributable to customers located in the United States.
Recently Issued ASUs - Revenue from Contracts with Customers (Topic 606)Adopted Accounting Standards
Income Taxes. In May 2014,December 2019, the FASB issuedreleased ASU No. 2014-09, Revenue from Contracts with Customers (“2019-12 (“ASU 2014-09”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 requires an entity to recognize revenue in a manner that depicts the transfer of goods or services to customers at an amount that reflects the consideration to which the entity expects to be entitled in exchange for those goods or services. ASU 2014-09 will replace most of the existing revenue recognition requirements in GAAP when it becomes effective. The standard can be applied using either the full retrospective approach or a modified retrospective approach at the date of adoption. This will beis effective for annual and interim reporting periodsfiscal years beginning after December 15, 2017.
Credit Losses. In August 2015, the FASB issued ASU No. 2015-14, deferring the effective date of ASU 2014-09 by one year. In MarchJune 2016, the FASB issued ASU No. 2016-08, Revenue from Contracts2016-13, Financial Instruments-Credit Losses (Topic 326): Measurement 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 Customers - Principal versus Agent Considerations (Reporting Revenue Gross versus Net). Under this update, anmore decision-useful information about the expected credit losses on financial instruments and other commitments to extend credit held by a reporting entity should recognize revenue to depict the transfer of promised goods or services to customers in an amount that reflects the consideration to which the entity expectsat each reporting date. The guidance is to be entitled in exchange for those goods or services. This update allows for either full retrospective adoption orapplied using a modified retrospective adoption. 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 Company’s consolidated financial statements or disclosures.
Recently Issued Accounting Standards
In April 2016,March 2020, the FASB issued ASU No. 2016-10, 2020-04, Reference Rate Reform (Topic 848): Facilitation 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 a limited period of time to ease the potential burden in accounting for (or recognizing the effects of)
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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 August 2020, the FASB issued ASU No. 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 complexity 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 2020-06 is effective for fiscal years beginning after December 15, 2021, with early adoption permitted. The Company will adopt ASU 2020-06 effective January 1, 2022. The adoption of ASU 2020-06 is not expected to have a material impact on the Company’s consolidated financial 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 which gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of NGLs and residue gas. The Company evaluates whether the processing entity is the principal or the agent in the transaction for each of our natural gas 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 transfers to the purchaser at the delivery point based on the contractual index price received.
The Company recognizes revenue for natural gas and NGLs on a gross basis with gathering, transportation and processing fees recognized separately as “Gathering, transportation and processing” in its consolidated statements of operations as the Company maintains control throughout processing.
Oil and gas purchase and sale arrangements
Sales of purchased oil and gas represent revenues the Company receives from sales of commodities purchased from a third-party. The Company recognizes these revenues and the purchase of the third-party commodities, as well as any costs associated with the purchase, on a gross basis, as the Company acts as a principal in these transactions by assuming control of the purchased commodity before it is transferred to the customer.
Accounts Receivable from Revenues from Contracts with Customers - Identifying Performance Obligations
Net accounts receivable include amounts billed and Licensingcurrently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2021 and 2020 of $171.8 million and $100.3 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets.
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
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(“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”). This update clarifies two principlesThe Company funded the cash portion of Accounting Standards Codification Topic 606: identifying performance obligationsthe 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 licensing implementation guidance. In May 2016,remaining shares will be released twelve months after the FASB issuedclosing 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.
| 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 | |||||||
| 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 | |||||||
| $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.
| Evaluated oil and natural gas properties | $ | 137,368 | |
| Unevaluated oil and natural gas properties | 509,359 | ||
| Asset retirement obligations | (168 | ) | |
| Net assets acquired | $ | 646,559 | |
| Evaluated oil and natural gas properties | $ | 65,043 | |
| Unevaluated oil and natural gas properties | 274,664 | ||
| Asset retirement obligations | (20 | ) | |
| Net assets acquired | $ | 339,687 | |
| Evaluated oil and natural gas properties | $ | 96,194 | |
| Unevaluated oil and natural gas properties | 233,387 | ||
| Asset retirement obligations | (8 | ) | |
| Net assets acquired | $ | 329,573 | |
| Twelve Months Ended December 31, | |||||||||||||||
| 2017 | (a) | 2016 | (a) | 2015 | (a) | ||||||||||
| Revenues | $ | 369,527 | $ | 243,273 | $ | 168,506 | |||||||||
| Income (loss) from operations | 144,104 | (39,730 | ) | (131,435 | ) | ||||||||||
| Income (loss) available to common stockholders | 115,787 | (82,612 | ) | (153,735 | ) | ||||||||||
| | |||||||||||||||
| Net income (loss) per common share: | |||||||||||||||
| Basic | $ | 0.57 | $ | (0.50 | ) | $ | (1.18 | ) | |||||||
| Diluted | $ | 0.57 | $ | (0.50 | ) | $ | (1.18 | ) | |||||||
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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 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 with information available at that time.
For the period from the closing date of the Carrizo Acquisition on December 20, 2019 through December 31, 2019, approximately $28.6 million of revenues and $7.0 million of direct operating expenses were included in the Company’s consolidated statements of operations for the year ended December 31, 2019.
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Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the year ended December 31, 2019 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 revenue, lease operating expenses, production taxes, depreciation,(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 amortization expense, accretion expense, interest expensenatural gas properties and capitalized interest.(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.
| 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 | |||||||
In 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 for the years ended December 31, 2020 and 2019, 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 included 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 as the divestitures did not significantly alter the relationship between capitalized costs and estimated proved reserves.
Note 5 – Property and Equipment, Net
As of December 31, 2021 and 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 | ||||||||||||
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The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $47.4 million for the Ameredev Transaction, Big Star Transaction,year ended December 31, 2021 and $36.2 million for the Plymouth Transaction have been commingled with our existingyears ended December 31, 2020 and 2019.
The Company capitalized interest costs to unproved properties totaling $99.6 million, $88.6 million and it is impractical$78.5 million for the years ended December 31, 2021, 2020 and 2019, respectively.
Impairment of Evaluated Oil and 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 provideamortization as of December 31, 2021 were incurred in the stand-alone operational results related to these properties.following periods:
| 2021 | 2020 | 2019 | 2018 and Prior | Total | ||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||
| Unevaluated property costs | $401,403 | $113,079 | $479,836 | $818,509 | $1,812,827 | |||||||||||||||||||||||||||
Note 4-6– 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 (loss) per share includes the potential dilutive impact of non-vested restricted shares and unexercised optionswarrants 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.
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The following table sets forth the computation of basic and diluted earnings per share:
| (share amounts in thousands) | For the Year Ended December 31, | |||||||||||
| 2017 | 2016 | 2015 | ||||||||||
| Net income (loss) | $ | 120,424 | $ | (91,813 | ) | $ | (240,139 | ) | ||||
| Preferred stock dividends | (7,295 | ) | (7,295 | ) | (7,895 | ) | ||||||
| Income (loss) available to common stockholders | $ | 113,129 | $ | (99,108 | ) | $ | (248,034 | ) | ||||
| | ||||||||||||
| Weighted average shares outstanding | 201,526 | 126,258 | 65,708 | |||||||||
| Dilutive impact of restricted stock | 576 | — | — | |||||||||
Weighted average shares outstanding for diluted income (loss) per share (a) | 202,102 | 126,258 | 65,708 | |||||||||
| | ||||||||||||
| Basic income (loss) per share | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | ||||
| Diluted income (loss) per share | $ | 0.56 | $ | (0.78 | ) | $ | (3.77 | ) | ||||
| | ||||||||||||
Stock options (b) | — | 15 | 15 | |||||||||
Restricted stock (b) | 16 | — | 126 | |||||||||
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands, except per share amounts) | ||||||||||||||||||||
| Net Income (Loss) | $365,151 | ($2,533,621) | $67,928 | |||||||||||||||||
Preferred stock dividends (1) | — | — | (3,997) | |||||||||||||||||
| Loss on redemption of preferred stock | — | — | (8,304) | |||||||||||||||||
| Income (Loss) Available to Common Stockholders | $365,151 | ($2,533,621) | $55,627 | |||||||||||||||||
| Basic weighted average common shares outstanding | 48,612 | 39,718 | 23,313 | |||||||||||||||||
| Dilutive impact of restricted stock | 296 | — | 27 | |||||||||||||||||
| Dilutive impact of warrants | 1,403 | — | — | |||||||||||||||||
| Diluted weighted average common shares outstanding | 50,311 | 39,718 | 23,340 | |||||||||||||||||
| Income (Loss) Available to Common Stockholders Per Common Share | ||||||||||||||||||||
| Basic | $7.51 | ($63.79) | $2.39 | |||||||||||||||||
| Diluted | $7.26 | ($63.79) | $2.38 | |||||||||||||||||
Restricted stock (2) | 7 | 581 | 90 | |||||||||||||||||
Warrants (2) | 481 | 2,564 | 9 | |||||||||||||||||
(1) The Company redeemed all outstanding shares of its 10% Series A Cumulative Preferred Stock (“Preferred Stock”) on July 18, 2019 and all dividends ceased to accrue upon redemption.
(2) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.
Note 57– Borrowings
The Company’s borrowings consisted of the following at:following:
| As of December 31, | ||||||||||||||||||||
| 2021 | 2020 | |||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| 6.25% Senior Notes due 2023 | $— | $542,720 | ||||||||||||||||||
| 6.125% Senior Notes due 2024 | 460,241 | 460,241 | ||||||||||||||||||
| Senior Secured Revolving Credit Facility due 2024 | 785,000 | 985,000 | ||||||||||||||||||
| 9.00% Second Lien Senior Secured Notes due 2025 | 319,659 | 516,659 | ||||||||||||||||||
| 8.25% Senior Notes due 2025 | 187,238 | 187,238 | ||||||||||||||||||
| 6.375% Senior Notes due 2026 | 320,783 | 320,783 | ||||||||||||||||||
| 8.00% Senior Notes due 2028 | 650,000 | — | ||||||||||||||||||
| Total principal outstanding | 2,722,921 | 3,012,641 | ||||||||||||||||||
| Unamortized premium on 6.25% Senior Notes | — | 2,917 | ||||||||||||||||||
| Unamortized premium on 6.125% Senior Notes | 2,373 | 3,236 | ||||||||||||||||||
| Unamortized discount on Second Lien Notes | (14,852) | (41,820) | ||||||||||||||||||
| Unamortized premium on 8.25% Senior Notes | 2,477 | 3,240 | ||||||||||||||||||
| Unamortized deferred financing costs for Second Lien Notes | (2,910) | (3,931) | ||||||||||||||||||
| Unamortized deferred financing costs for Senior Notes | (15,894) | (7,019) | ||||||||||||||||||
Total carrying value of borrowings (1) | $2,694,115 | $2,969,264 | ||||||||||||||||||
| | As of December 31, | |||||||
| 2017 | 2016 | |||||||
| Principal components: | ||||||||
| Senior secured revolving credit facility | $ | 25,000 | $ | — | ||||
| 6.125% Senior Notes | 600,000 | 400,000 | ||||||
| Total principal outstanding | 625,000 | 400,000 | ||||||
| Premium on 6.125% Senior Notes, net of accumulated amortization | 7,594 | — | ||||||
| Unamortized deferred financing costs | (12,398 | ) | (9,781 | ) | ||||
| Total carrying value of borrowings | $ | 620,196 | $ | 390,219 | ||||
Senior Secured Revolving CreditFacility
The Company has a senior secured revolving credit facility with a syndicate of lenders (the “Credit Facility”)
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are outstanding at such time, and (ii) if the Second Lien Notes, as defined below, are outstanding at such time, the date which is 182 days prior to the maturity of any of the 6.125% Senior Notes, to the extent a principal amount of more than $100.0 million with a maturity daterespect to each such issuance is outstanding as of May 25, 2022. JPMorgan Chase Bank, N.A. is Administrative Agent,such date), when the credit agreement matures and participants include 17 institutional lenders.any outstanding borrowings are due. The total notional amount availableborrowing base under the Credit Facilitycredit agreement is $2,000,000. Amounts borrowed undersubject to regular redeterminations in the Credit Facilityspring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may not exceedreduce the amount of the borrowing base, which is generally reviewed on a semi-annual basis.base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. Concurrent with
On May 3, 2021, the executionCompany entered into the fourth amendment to its credit agreement governing the Credit Facility, which, among other things, (a) reaffirmed, as of the Sixth Amended and Restated Credit Agreement,date of the Credit Facility’sfourth amendment, the borrowing base increased to $650,000, butand the Company elected an aggregate commitment amount of $500,000. $1.6 billion; and (b) permits, subject to certain liquidity and free cash flow metrics, the prepayment, repurchase or redemption, commencing on April 1, 2021, of up to an aggregate amount of $100.0 million of Junior Debt (as defined in the credit agreement governing the Credit Facility), which includes the Senior Unsecured Notes (as defined below) and the Second Lien Notes (as defined below).
On November 7, 2017,1, 2021, the Company entered into the fifth amendment to its credit agreement governing the Credit Facility’sFacility, which, among other things, reaffirmed, as of the date of the fifth amendment, the borrowing base increasedand elected commitment amount of $1.6 billion.
Borrowings outstanding under the credit agreement bear interest at the Company’s option at either (i) a base rate for a base rate loan plus a margin between 1.00% to $700,000 with2.00%, where the base rate is defined as the greatest of the prime rate, the federal funds rate plus 0.50% and the adjusted LIBO rate plus 1.00%, or (ii) an adjusted LIBO rate for a reaffirmedEurodollar loan plus a margin between 2.00% to 3.00%. The Company also incurs commitment of $500,000, following the semi-annual review.
Second Lien Notes
Exchange. On November 5, 2021, the Company closed on its transaction with Chambers Investments, LLC (“Kimmeridge”), a private investment vehicle managed by Kimmeridge Energy Management, LLC, to exchange $197.0 million of its outstanding Second Lien Notes for a notional amount of approximately $223.1 million of the Company’s common stock. The value of equity to be delivered was based on the optional redemption language in the indenture for the Second Lien Notes. The price of the Company’s common stock used to calculate the shares issued was based on the 10-day volume-weighted average price as of August 2, 2021 and equated to 5.5 million shares. As a result of the Second Lien Note Exchange, the Company recognized a loss on the extinguishment of debt of approximately $43.4 million in its consolidated statement of operations for the year ended December 31, 2017, the Credit Facility had a weighted-average interest rate of 3.11%,2021, calculated as the LIBOR plus a tiered rate ranging from 2.00% to 3.00%, which is determined based on utilizationnotional amount of the facility. In addition, the Credit Facility carries a commitment fee of 0.375% per annum, payable quarterly, on the unused portion of the borrowing base.
Issuance.On May 19, 2017,September 30, 2020, the Company issued an additional $200,000(i) $300.0 million in aggregate principal amount of its 6.125%9.00% Second Lien Senior Secured Notes whichdue 2025 (the “September 2020 Second Lien Notes”) and (ii) warrants for 7.3 million shares of the Company’s common stock, with a term of five years and an exercise price of $5.60 per share, exercisable only on a net share settlement basis (the “September 2020 Warrants”). Net proceeds were allocated to the September 2020 Warrants based on their fair value on the date of issuance with the existing $400,000remaining net proceeds allocated to the September 2020 Second Lien Notes. The fair value of the September 2020 Warrants was calculated by a third-party valuation specialist using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
| Issuance Date Fair Value Assumptions | ||||||||
| Exercise price | $5.60 | |||||||
| Expected term (in years) | 5.0 | |||||||
| Expected volatility | 116.3 | % | ||||||
| Risk-free interest rate | 0.3 | % | ||||||
| Dividend yield | — | % | ||||||
See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion of the September 2020 Warrants.
On November 2, 2020, in connection with the Senior Unsecured Notes exchange described below, the Company issued (i) $216.7 million in aggregate principal amount of 6.125%9.00% Second Lien Senior Secured Notes are treated as a single class of notes underdue 2025 (the “November 2020 Second Lien Notes” and together with the indenture. The net proceedsSeptember 2020 Second Lien Notes, the “Second Lien Notes”) and (ii) warrants for approximately 1.75 million shares of the offering, includingCompany’s common stock, with a premium issueterm of five years and an exercise price of 104.125%$5.60 per share, exercisable only on a net share settlement basis (the “November 2020 Warrants”). The fair value of the November 2020 Second Lien Notes was calculated by a third-party valuation specialist using a discounted cash flow model. Significant inputs into the calculation included the redemption premiums, described below, as well as redemption assumptions provided by the Company. The fair value of the November
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2020 Warrants was calculated using a Black-Scholes-Merton option pricing model, incorporating the following assumptions at the issuance date:
| Issuance Date Fair Value Assumptions | ||||||||
| Exercise price | $5.60 | |||||||
| Expected term (in years) | 4.9 | |||||||
| Expected volatility | 98.4 | % | ||||||
| Risk-free interest rate | 0.4 | % | ||||||
| Dividend yield | — | % | ||||||
As the November 2020 Second Lien Notes were issued with the November 2020 Warrants, the $216.7 million aggregate principal amount was allocated between the November 2020 Second Lien Notes and after deducting initial purchasers’ discountsthe November 2020 Warrants based on their relative fair values at the exchange date. This resulted in $207.6 million allocated to the November 2020 Second Lien Notes and estimated offering expenses, were approximately $206,139. $9.1 million allocated to the November 2020 Warrants.
The Company usedSecond Lien Notes will mature on the proceeds,earlier of (i) April 1, 2025 and (ii) 91 days prior to the maturity date of any outstanding unsecured notes in part, to fund an acquisition completeda principal amount at or greater than $100.0 million and have interest payable semi-annually each April 1 and October 1, commencing on June 5, 2017 (discussed further in Note 3) and for general corporate purposes.
April 1, 2021.
The Company may redeem the 6.125% SeniorSecond Lien Notes in accordance with the following terms;terms: (1) prior to October 1, 2019,2022, a redemption of up to 35% of the principal in an amount not greater than the net proceeds from certain equity offerings, and within 180 days of the closing date of such equity offerings, at a redemption price of 106.125%109.00% of principal, plus accrued and unpaid interest, if any, to, but excluding, the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to October 1, 2019,2022, a redemption of all or part of the principal at a price of 100% of the principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to, but excluding, the date of the redemption; and (3) subsequent to October 1, 2022, a redemption, in whole or in part, at redemption prices decreasing annually from 105.00% to 100% of the principal amount redeemed plus accrued and unpaid interest.
Upon the occurrence of certain change of control events, each holder of the Second Lien Notes may require the Company to repurchase all or a redemptionportion of the Second Lien Notes at a price of 101% of the principal amount repurchased, plus accrued and unpaid interest, if any, to, but excluding, the date of repurchase.
Senior Unsecured Notes
8.00% Senior Notes.On July 6, 2021, the Company issued $650.0 million aggregate principal amount of 8.00% Senior Notes due 2028 (the “8.00% Senior Notes”) in a private placement for proceeds of approximately $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.
At any time prior to August 1, 2024, the Company may, from time to time, redeem up to 35% of the aggregate principal amount of the 8.00% Senior Notes in an amount of cash not greater than the net cash proceeds from certain equity offerings at the redemption (i)price of 104.594%108.00% of the principal amount, plus accrued and unpaid interest, if any, to, but excluding, the date of redemption, if at least 65% of the aggregate principal amount of the 8.00% Senior Notes remains outstanding after such redemption and the redemption occurs within 180 days of the closing date of such equity offering. Prior to August 1, 2024, the Company may, at its option, on any one or more occasions, redeem all or a portion of the 8.00% Senior Notes at 100.00% of the principal amount plus an applicable make-whole premium and accrued and unpaid interest. On or after August 1, 2024, the Company may redeem all or a portion of the 8.00% Senior Notes at redemption prices decreasing annually from 104.00% to 100.00% of the principal amount redeemed plus accrued and unpaid interest. Upon the occurrence of certain kinds of change of control, the Company must make an offer to repurchase all or a portion of each holder’s 8.00% Senior Notes for cash at a price equal to 101% of the aggregate principal amount, plus accrued and unpaid interest.
Redemption of 6.25% Senior Notes.On June 21, 2021, the Company delivered a redemption notice with respect to all $542.7 million of its outstanding 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”), which became redeemable on July 21, 2021. The Company used a portion of the net proceeds from the 8.00% Senior Notes to redeem all of its outstanding 6.25% Senior Notes and the remaining proceeds to partially repay amounts outstanding under the Credit Facility. The Company recognized a gain on extinguishment of debt of approximately $2.4 million in its consolidated statements of operations for the year ended December 31, 2021, which was primarily related to writing off the remaining unamortized premium associated with the 6.25% Senior Notes.
Senior Unsecured Notes Exchange. On November 13, 2020, the Company closed on the agreement by and among the Company and certain holders (the “Holders”) of the Company’s 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, and 6.375% Senior Notes (each as defined in this footnote and together the “Senior Unsecured Notes”) to exchange $389.0 million of aggregate principal
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amount of the Senior Unsecured Notes held by the Holders for $216.7 million aggregate principal amount of Second Lien Notes, as further described above.
The Company assessed the debt exchange to determine whether it should be accounted for pursuant to the FASB’s Accounting Standard Codification (“ASC”) Topic 470-60, Troubled Debt Restructurings by Debtors, or pursuant to ASC Topic 470-50, Modifications and Extinguishments (“ASC 470-50”). This assessment requires judgments to be made with respect to whether or not an entity is experiencing financial difficulty. It was determined that the Company was not experiencing financial difficulty and could obtain funds at market rates similar to other non-troubled debtors, therefore the Company accounted for the exchange as an extinguishment of debt in accordance with ASC 470-50. The Company recognized a gain on the extinguishment of debt of $170.4 million in its consolidated statement of operations for the year ended December 31, 2020, which consisted of the carrying values of the Senior Unsecured Notes exchanged less the aggregate principal amount of the November 2020 Second Lien Notes issued, net of associated unamortized debt discount of $9.1 million, which was based on the November 2020 Second Lien Notes’ allocated fair value on the exchange date.
6.125%Senior Notes.The Company’s 6.125% Senior Notes mature on October 1, 2019, but before2024 and have interest payable semi-annually each April 1 and October 1, 2020, and (ii)1. The Company may redeem all or a portion of 103.063% of principal if the 6.125% Senior Notes at redemption occurs on or after October 1, 2020, but before October 1, 2022, and (iii) of 101.531% of principal if the redemption occurs on or after October 1, 2021, but before October 1, 2022, and (iv) ofprices decreasing annually from 104.594% to 100% of the principal if the redemption occurs on or after October 1, 2022.
amount plus accrued and unpaid interest. Following a change of control, each holder of the 6.125% Senior Notes may require the Company to repurchase all or a portion of the 6.125% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest.
8.25% Senior Notes. The Company’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”), which were assumed upon consummation of the Merger, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. The Company 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. Following a change of control, each holder of the 8.25% Senior Notes may require the Company to repurchase the 8.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest.
6.375% Senior Notes.On June 7, 2018, the Company 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.
Since July 1, 2021, the Company may redeem all or a portion of the 6.375% Senior Notes at redemption prices decreasing annually from 103.188% to 100% of the principal amount redeemed plus accrued and unpaid interest. Following a change of control, each holder of the 6.375% Senior Notes may require the Company to repurchase all or a portion of the 6.375% Senior Notes at a price of 101% of principal of the amount repurchased, plus accrued and unpaid interest, if any, to the date of repurchase.
Restrictive Covenants
The term loan was secured by junior liens on properties mortgaged underCompany’s credit agreement governing the Credit Facility subject to an intercreditor agreement.
Under the credit agreement, the Company 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 (as defined in the credit agreement governing the Credit Facility) of no more than 3.00 to 1.00 and (2) commencing March 31, 2022 and for each quarter ending thereafter, a Leverage Ratio (as defined in the credit agreement governing the Credit Facility) of no more than 4.00 to 1.00; and (3) a Current Ratio (as defined in the credit agreement governing the Credit Facility) of not less than 1.00 to 1.00. The Company was in compliance with these covenants at December 31, 2017.2021.
The credit agreement governing the Credit Facility and the indentures governing the Company’s Senior Unsecured Notes also place restrictions on the Company and certain of its subsidiaries with respect to additional indebtedness, liens, dividends and other payments to shareholders, repurchases or redemptions of the Company’s common stock, redemptions of senior notes, investments, acquisitions, mergers, asset dispositions, transactions with affiliates, hedging transactions and other matters.
The credit agreement and indentures are subject to customary events of default. If an event of default occurs and is continuing, the holders or lenders may elect to accelerate amounts due (except in the case of a bankruptcy event of default, in which case such amounts will automatically become due and payable).
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Note 6-8 – Derivative Instruments and Hedging Activities
Objectives and strategiesStrategies for using derivative instruments
Using Derivative Instruments
The Company is exposed to fluctuations in oil, and natural gas and NGL prices received for its production. Consequently, the Company believes it is prudent to manage the variability in cash flows on a portion of its oil, and natural gas and NGL production. The Company utilizes a mix of collars, swaps, and put and call options and similar derivative financial instruments to manage fluctuations in cash flows resulting from changes in commodity prices. The Company does not use these instruments for speculative or trading purposes.
Counterparty riskRisk and offsetting
Offsetting
The use ofCompany typically has numerous commodity derivative instruments exposesoutstanding with a counterparty that were executed at various dates, for various contract types, commodities and time periods. This often results in both commodity derivative asset and liability positions with that counterparty. The Company nets its commodity derivative instrument fair values executed with the same counterparty to a single asset or liability pursuant to ISDA Agreements, which provide for net settlement over the term of the contract and in the event of default or termination of the contract. In general, if a party to a derivative transaction incurs an event of default, as defined in the applicable agreement, the other party will have the right to demand the posting of collateral, demand a cash payment transfer or terminate the arrangement.
As of December 31, 2021, the Company has outstanding commodity derivative instruments with 10 counterparties to minimize its credit exposure to any individual counterparty. All of the counterparties to the Company’s commodity derivative instruments are also lenders under the Company’s credit agreement. Therefore, each of the Company’s counterparties allow the Company to satisfy any need for margin obligations associated with commodity derivative instruments where the Company is in a net liability position with the collateral securing the credit agreement, thus eliminating the need for independent collateral posting.
Because each of the Company’s counterparties has an investment grade credit rating, the Company believes it does not have significant credit risk that a counterparty will be unableand accordingly does not currently require its counterparties to meetpost collateral to support the net asset positions of its commitments. commodity derivative instruments. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each counterparty.
While the Company monitors counterparty creditworthiness on an ongoing basis, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments under lower commodity prices while continuing to be obligated under higher commodity price contracts subject to any right of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument; see Note 7instrument. See “Note 9 - Fair Value Measurements” for additional information regarding fair value.further discussion.
Contingent Consideration Arrangements
Ranger Divestiture.The Company’s Ranger Divestiture provided for potential contingent consideration to be received by the Company executes commodity derivative contracts under master agreementsif the average of the final monthly settlements for each month of 2021 for NYMEX Light Sweet Crude Oil Futures exceeded the pricing threshold of $60.00 for the year 2021. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. As the specified pricing threshold for 2021 was met, in March 2022, the Company will receive $20.8 million, of which $8.5 million will be presented in cash flows from financing activities with netting provisions that providethe remaining $12.3 million presented in cash flows from operating activities. The Ranger Divestiture contingent consideration expired at the end of 2021.
Carrizo Acquisition Contingent Consideration. As a result of the Carrizo Acquisition, the Company acquired the Contingent ExL Consideration where the Company could be required to remit payments if the average daily closing spot price of WTI crude oil exceeded the pricing threshold of $50.00 for offsetting assets against liabilities.each of the years 2019, 2020 and 2021. The specified pricing threshold for 2020 was not met, therefore there was no payment made for the Contingent ExL Consideration in January 2021. In general, if a party to a derivative transaction incurs an event of default,January 2020, the Company paid $50.0 million as definedthe specified pricing threshold for 2019 was met. This cash payment is classified as cash flows from investing activities in the applicable agreement,consolidated statements of cash flows. Additionally, as the specified pricing threshold for 2021 was met, in January 2022, the Company paid $25.0 million, of which $19.2 million will be presented in cash flows from investing activities with the remaining $5.8 million presented in cash flows from operating activities. The Contingent ExL Consideration expired at the end of 2021.
Additionally, as part of the Carrizo Acquisition, the Company acquired other party will havecontingent consideration arrangements where the right to demandCompany could receive payments if certain pricing thresholds were met in 2019 and 2020, which ranged between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. The specified pricing thresholds for each of these other contingent consideration arrangements for 2020 were not met, therefore there were no payments from the postingcontingent consideration arrangements acquired in the Carrizo Acquisition in January 2021. In January 2020, the Company received $10.0 million as the specified pricing thresholds for 2019 were met for certain of collateral, demand athe contingent consideration arrangements. These cash payment transfer or terminate the arrangement.
receipts are classified as cash flows
79
Warrants
The Company determined that the September 2020 Warrants, as defined above in “Note 7 - Borrowings”, were required to be accounted for as a derivative instrumentinstrument. The Company recorded the September 2020 Warrants as a liability on its consolidated balance sheet measured at fair value as a component of “Fair value of derivatives” with gains and losses as a benchmark price, such as the NYMEX price. To determineresult of changes in the fair value of the Company’sSeptember 2020 Warrants recorded as “(Gain) loss on derivative instruments,contracts” in the consolidated statements of operations in the period in which the changes occur. See “Note 7 - Borrowings” and “Note 9 - Fair Value Measurements” for additional details.
In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. As a result of this exercise, the Company utilizes presentissued 5.6 million shares of its common stock in exchange for all of the outstanding September 2020 Warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability, which was $134.8 million at the time of exercise, and the fair value methods that include assumptions about commodity prices based on those observedof the September 2020 Warrants at exercise, less the par value of the shares of common stock issued in underlying markets. See Note 7 for additional information regarding fair value.the exercise, was reclassified to “Capital in excess of par value” in the consolidated balance sheets.
Financial Statement Presentation and Settlements
The Company records its derivative contractsinstruments at fair value in the consolidated balance sheets and records changes in fair value as a gain or“(Gain) loss on derivative contractscontracts” in the consolidated statements of operations. Cash settlementsSettlements are also recorded as a gain or“(Gain) loss on derivative contractscontracts” in the consolidated statements of operations.
The following table reflects the fair value of the Company’s derivative instruments for the periods presented:
| | Balance Sheet Presentation | Asset Fair Value | Liability Fair Value | Net Derivative Fair Value | ||||||||||||||||||||||||
| Commodity | Classification | Line Description | 12/31/2017 | 12/31/2016 | 12/31/2017 | 12/31/2016 | 12/31/2017 | 12/31/2016 | ||||||||||||||||||||
| Natural gas | Current | Fair value of derivatives | $ | 406 | $ | — | $ | — | $ | (593 | ) | $ | 406 | $ | (593 | ) | ||||||||||||
| Oil | Current | Fair value of derivatives | — | 103 | (27,744 | ) | (17,675 | ) | (27,744 | ) | (17,572 | ) | ||||||||||||||||
| Oil | Non-current | Fair value of derivatives | — | — | (1,284 | ) | (28 | ) | (1,284 | ) | (28 | ) | ||||||||||||||||
| Totals | $ | 406 | $ | 103 | $ | (29,028 | ) | $ | (18,296 | ) | $ | (28,622 | ) | $ | (18,193 | ) | ||||||||||||
| As of December 31, 2021 | |||||||||||||||||
| Presented without | As Presented with | ||||||||||||||||
| Effects of Netting | Effects of Netting | Effects of Netting | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Assets | |||||||||||||||||
| Commodity derivative instruments | $25,469 | ($23,921) | $1,548 | ||||||||||||||
| Contingent consideration arrangements | 20,833 | — | 20,833 | ||||||||||||||
| Fair value of derivatives - current | $46,302 | ($23,921) | $22,381 | ||||||||||||||
| Commodity derivative instruments | $1,119 | ($869) | $250 | ||||||||||||||
| Contingent consideration arrangements | — | — | — | ||||||||||||||
| Other assets, net | $1,119 | ($869) | $250 | ||||||||||||||
| Liabilities | |||||||||||||||||
Commodity derivative instruments (1) | ($184,898) | $23,921 | ($160,977) | ||||||||||||||
| Contingent consideration arrangements | (25,000) | — | (25,000) | ||||||||||||||
| Fair value of derivatives - current | ($209,898) | $23,921 | ($185,977) | ||||||||||||||
| Commodity derivative instruments | ($12,278) | $869 | ($11,409) | ||||||||||||||
| Contingent consideration arrangements | — | — | — | ||||||||||||||
| Fair value of derivatives - non current | ($12,278) | $869 | ($11,409) | ||||||||||||||
(1) Includes approximately $2.9 million of deferred premiums, which will be paid as the applicable contracts settle.
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| | For the Year Ended December 31, 2017 | |||||||
| | Presented without | As Presented with | ||||||
| | Effects of Netting | Effects of Netting | Effects of Netting | |||||
| Current assets: Fair value of derivatives | 406 | — | 406 | |||||
| | ||||||||
| Current liabilities: Fair value of derivatives | (27,744 | ) | — | (27,744 | ) | |||
| Long-term liabilities: Fair value of derivatives | (1,284 | ) | — | (1,284 | ) | |||
| | For the Year Ended December 31, 2016 | |||||||
| | Presented without | As Presented with | ||||||
| | Effects of Netting | Effects of Netting | Effects of Netting | |||||
| Current assets: Fair value of derivatives | 1,836 | (1,733 | ) | 103 | ||||
| Current liabilities: Fair value of derivatives | (20,001 | ) | 1,733 | (18,268 | ) | |||
| Long-term liabilities: Fair value of derivatives | (28 | ) | — | (28 | ) | |||
| | For the Year Ended December 31, | |||||||||||
| | 2017 | 2016 | 2015 | |||||||||
| Oil derivatives | ||||||||||||
| Net gain (loss) on settlements | $ | (9,067 | ) | $ | 17,801 | $ | 33,299 | |||||
| Net loss on fair value adjustments | (11,426 | ) | (37,543 | ) | (5,403 | ) | ||||||
| Total gain (loss) on oil derivatives | $ | (20,493 | ) | $ | (19,742 | ) | $ | 27,896 | ||||
| Natural gas derivatives | ||||||||||||
| Net gain on settlements | $ | 594 | $ | 102 | $ | 1,717 | ||||||
| Net gain (loss) on fair value adjustments | 998 | (593 | ) | (1,255 | ) | |||||||
| Total gain (loss) on natural gas derivatives | $ | 1,592 | $ | (491 | ) | $ | 462 | |||||
| | ||||||||||||
| Total gain (loss) on oil & natural gas derivatives | $ | (18,901 | ) | $ | (20,233 | ) | $ | 28,358 | ||||
| As of December 31, 2020 | |||||||||||||||||
| Presented without | As Presented with | ||||||||||||||||
| Effects of Netting | Effects of Netting | Effects of Netting | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Assets | |||||||||||||||||
| Commodity derivative instruments | $21,156 | ($20,235) | $921 | ||||||||||||||
| Contingent consideration arrangements | — | — | — | ||||||||||||||
| Fair value of derivatives - current | $21,156 | ($20,235) | $921 | ||||||||||||||
| Commodity derivative instruments | $— | $— | $— | ||||||||||||||
| Contingent consideration arrangements | 1,816 | — | 1,816 | ||||||||||||||
| Other assets, net | $1,816 | $— | $1,816 | ||||||||||||||
| Liabilities | |||||||||||||||||
Commodity derivative instruments (1) | ($117,295) | $20,235 | ($97,060) | ||||||||||||||
| Contingent consideration arrangements | — | — | — | ||||||||||||||
| Fair value of derivatives - current | ($117,295) | $20,235 | ($97,060) | ||||||||||||||
| Commodity derivative instruments | $— | $— | $— | ||||||||||||||
| Contingent consideration arrangements | (8,618) | — | (8,618) | ||||||||||||||
| September 2020 Warrants liability | (79,428) | — | (79,428) | ||||||||||||||
| Fair value of derivatives - non current | ($88,046) | $— | ($88,046) | ||||||||||||||
(1) Includes approximately $11.2 million of deferred premiums, which will be paid as the applicable contracts settle.
The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:
| Years Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| (Gain) loss on oil derivatives | $429,156 | ($48,031) | $73,313 | ||||||||||||||
| (Gain) loss on natural gas derivatives | 33,621 | 14,883 | (8,889) | ||||||||||||||
| (Gain) loss on NGL derivatives | 6,768 | 2,426 | — | ||||||||||||||
| (Gain) loss on contingent consideration arrangements | (2,635) | 2,976 | (2,315) | ||||||||||||||
| (Gain) loss on September 2020 Warrants liability | 55,390 | 55,519 | — | ||||||||||||||
| (Gain) loss on derivative contracts | $522,300 | $27,773 | $62,109 | ||||||||||||||
The components of “Cash received (paid) for commodity derivative settlements, net” and “Cash paid for settlements of contingent consideration arrangements, net” are as follows for the respective periods:
| Years Ended December 31, | |||||||||||||||||
| 2021 | 2020 | 2019 | |||||||||||||||
| (In thousands) | |||||||||||||||||
| Cash flows from operating activities | |||||||||||||||||
| Cash received (paid) on oil derivatives | ($350,340) | $98,723 | ($11,188) | ||||||||||||||
| Cash received (paid) on natural gas derivatives | (34,576) | 147 | 7,399 | ||||||||||||||
| Cash received (paid) on NGL derivatives | (10,181) | — | — | ||||||||||||||
| Cash received (paid) for commodity derivative settlements, net | ($395,097) | $98,870 | ($3,789) | ||||||||||||||
| Cash flows from investing activities | |||||||||||||||||
| Cash paid for settlements of contingent consideration arrangements, net | $— | ($40,000) | $— | ||||||||||||||
81
Derivative positions
Positions
Listed in the tables below are the outstanding oil, and natural gas and NGL derivative contracts as of December 31, 2017:2021:
| For the Full Year | For the Full Year | |||||||||||||
| Oil Contracts (WTI) | 2022 | 2023 | ||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 5,891,000 | 497,000 | ||||||||||||
| Weighted average price per Bbl | $61.61 | $70.01 | ||||||||||||
| Collar Contracts | ||||||||||||||
| Total volume (Bbls) | 7,097,500 | — | ||||||||||||
| Weighted average price per Bbl | ||||||||||||||
| Ceiling (short call) | $67.70 | $— | ||||||||||||
| Floor (long put) | $56.15 | $— | ||||||||||||
Short Call Swaption Contracts 1 | ||||||||||||||
| Total volume (Bbls) | — | 1,825,000 | ||||||||||||
| Weighted average price per Bbl | $— | $72.00 | ||||||||||||
| Oil Contracts (Midland Basis Differential) | ||||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 2,372,500 | — | ||||||||||||
| Weighted average price per Bbl | $0.50 | $— | ||||||||||||
| Oil Contracts (Argus Houston MEH) | ||||||||||||||
| Collar Contracts | ||||||||||||||
| Total volume (Bbls) | 452,500 | — | ||||||||||||
| Weighted average price per Bbl | ||||||||||||||
| Ceiling (short call) | $63.15 | $— | ||||||||||||
| Floor (long put) | $51.25 | $— | ||||||||||||
(1) The 2023 short call swaption contracts have exercise expiration dates of December 30, 2022.
| For the Full Year | ||||||||||||||
| Natural Gas Contracts (Henry Hub) | 2022 | |||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (MMBtu) | 7,320,000 | |||||||||||||
| Weighted average price per MMBtu | $3.08 | |||||||||||||
| Collar Contracts | ||||||||||||||
| Total volume (MMBtu) | 7,880,000 | |||||||||||||
| Weighted average price per MMBtu | ||||||||||||||
| Ceiling (short call) | $3.91 | |||||||||||||
| Floor (long put) | $3.08 | |||||||||||||
| Natural Gas Contracts (Waha Basis Differential) | ||||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (MMBtu) | 5,475,000 | |||||||||||||
| Weighted average price per MMBtu | ($0.21) | |||||||||||||
82
| For the Full Year of | For the Full Year of | |||||||
| Oil contracts (WTI) | 2018 | 2019 | ||||||
| Swap contracts | ||||||||
| Total volume (MBbls) | 2,009 | — | ||||||
| Weighted average price per Bbl | $ | 51.78 | $ | — | ||||
| Collar contracts (two-way collars) | ||||||||
| Total volume (MBbls) | 365 | — | ||||||
| Weighted average price per Bbl | ||||||||
| Ceiling (short call) | $ | 60.50 | $ | — | ||||
| Floor (long put) | $ | 50.00 | $ | — | ||||
| Collar contracts combined with short puts (three-way collars) | ||||||||
| Total volume (MBbls) | 3,468 | 730 | ||||||
| Weighted average price per Bbl | ||||||||
| Ceiling (short call option) | $ | 60.86 | $ | 58.50 | ||||
| Floor (long put option) | $ | 48.95 | $ | 50.00 | ||||
| Short put option | $ | 39.21 | $ | 40.00 | ||||
| For the Full Year of | For the Full Year of | |||||||
| Oil contracts (Midland basis differential) | 2018 | 2019 | ||||||
| Swap contracts | ||||||||
| Volume (MBbls) | 5,289 | — | ||||||
| Weighted average price per Bbl | $ | (0.86 | ) | $ | — | |||
| | For the Full Year of | For the Full Year of | ||||||
| Natural gas contracts | 2018 | 2019 | ||||||
| Collar contracts (Henry Hub, two-way collars) | ||||||||
| Total volume (BBtu) | 720 | — | ||||||
| Weighted average price per MMBtu | ||||||||
| Ceiling (short call option) | $ | 3.84 | $ | — | ||||
| Floor (long put option) | $ | 3.40 | $ | — | ||||
| For the Full Year | ||||||||||||||
| NGL Contracts (OPIS Mont Belvieu Purity Ethane) | 2022 | |||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 378,000 | |||||||||||||
| Weighted average price per Bbl | $15.70 | |||||||||||||
| NGL Contracts (OPIS Mont Belvieu Non-TET Propane) | ||||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 252,000 | |||||||||||||
| Weighted average price per Bbl | $48.43 | |||||||||||||
| NGL Contracts (OPIS Mont Belvieu Non-TET Butane) | ||||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 99,000 | |||||||||||||
| Weighted average price per Bbl | $54.39 | |||||||||||||
| NGL Contracts (OPIS Mont Belvieu Non-TET Isobutane) | ||||||||||||||
| Swap Contracts | ||||||||||||||
| Total volume (Bbls) | 54,000 | |||||||||||||
| Weighted average price per Bbl | $54.29 | |||||||||||||
| For the Full Year of | For the Full Year of | |||||||
| Oil contracts (WTI) | 2018 | 2019 | ||||||
| Collar contracts combined with short puts (three-way collars) | ||||||||
| Total volume (MBbls) | — | 1,095 | ||||||
| Weighted average price per Bbl | ||||||||
| Ceiling (short call option) | $ | — | $ | 65.00 | ||||
| Floor (long put option) | $ | — | $ | 55.00 | ||||
| Short put option | $ | — | $ | 45.00 | ||||
| Natural gas contracts | ||||||||
| Swap contracts (Henry Hub) | ||||||||
| Total volume (BBtu) | 3,366 | — | ||||||
| Weighted average price per MMBtu | $ | 2.95 | $ | — | ||||
Note 7 -9 – Fair Value Measurements
Level 1 – Observable inputs which consist of unadjustedsuch as quoted prices in active markets at the measurement date for identical, instruments in active markets. unrestricted assets or liabilities.
Level 2 inputs consist of quoted prices for similar instruments. Level 3 valuations are derived from– Other inputs that are significantobservable directly or indirectly such as quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability.
Level 3 – Unobservable inputs for which there is little or no market data and unobservable,which the Company makes its own assumptions about how market participants would price the assets and these valuations have the lowest priority.
liabilities.
Fair valueValue of financial instrumentsFinancial Instruments
Cash, cash equivalents,Cash Equivalents, and restricted investments.Restricted Investments. The carrying amounts for these instruments approximate fair value due to the short-term nature or maturity of the instruments.
Debt. The carrying amount of borrowings outstanding under the Company’s floating-rate debt approximatedCredit Facility approximates fair value becauseas the borrowings bear interest at variable rates were variable and are reflective of market rates. The following table presents the principal amounts of the Company’s Second Lien Notes and Senior Unsecured Notes with the fair values measured using quoted secondary market trading prices which are designated as Level 2 within the valuation hierarchy. See “Note 7 - Borrowings” for further discussion.
| | 2017 | 2016 | |||||||||||||
| | Carrying Value | Fair Value | Carrying Value | Fair Value | |||||||||||
Credit Facility (a) | $ | 25,000 | $ | — | $ | — | $ | — | |||||||
6.125% Senior Notes (b) | 595,196 | 618,000 | 390,219 | 412,000 | |||||||||||
| Total | $ | 620,196 | $ | 618,000 | $ | 390,219 | $ | 412,000 | |||||||
| December 31, 2021 | December 31, 2020 | |||||||||||||||||||||||||
| Principal Amount | Fair Value | Principal Amount | Fair Value | |||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||
6.25% Senior Notes | $— | $— | $542,720 | $344,627 | ||||||||||||||||||||||
| 6.125% Senior Notes | 460,241 | 455,639 | 460,241 | 260,036 | ||||||||||||||||||||||
| 9.00% Second Lien Notes | 319,659 | 343,633 | 516,659 | 470,160 | ||||||||||||||||||||||
| 8.25% Senior Notes | 187,238 | 184,429 | 187,238 | 100,172 | ||||||||||||||||||||||
| 6.375% Senior Notes | 320,783 | 309,556 | 320,783 | 161,995 | ||||||||||||||||||||||
| 8.00% Senior Notes | 650,000 | 663,000 | — | — | ||||||||||||||||||||||
| Total | $1,937,921 | $1,956,257 | $2,027,641 | $1,336,990 | ||||||||||||||||||||||
Assets and liabilities measuredLiabilities Measured at fair valueFair Value on a recurring basis
Recurring Basis
Certain assets and liabilities are reported at fair value on a recurring basis in the consolidated balance sheet. The following methods and assumptions were used to estimate fair value:
83
Commodity derivative instruments.Derivative Instruments. The fair value of commodity derivative instruments is derived using ana third-party income approach valuation model that utilizes market-corroborated inputs that are observable over the term of the commodity derivative contract. The Company’s fair value calculations also incorporate an estimate of the counterparties’ default risk for commodity derivative assets and an estimate of the Company’s default risk for commodity derivative liabilities. The Company believes that the majority ofAs the inputs used to calculatein the model are substantially observable over the term of the commodity derivative instruments fall within Level 2 of the fair value hierarchy based on thecontract and there is a wide availability of quoted market prices for similar commodity derivative contracts.contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See Note 6“Note 8 - Derivative Instruments and Hedging Activities” for additional information regardingfurther discussion.
Contingent Consideration Arrangements - Embedded Derivative Financial Instruments. The embedded options within the Company’s derivative instruments.contingent consideration arrangements are considered financial instruments under ASC 815. The Company engages a third-party valuation specialist using an option pricing model approach to measure the fair value of the embedded options on a recurring basis. The valuation includes significant inputs such as forward oil price curves, time to expiration, and implied volatility. The model provides for the probability that the specified pricing thresholds would be met for each settlement period, estimates undiscounted payouts, and risk adjusts for the discount rates inclusive of adjustments for each of the counterparty’s credit quality. As these inputs are substantially observable for the full term of the contingent consideration arrangements, the inputs are considered Level 2 inputs within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion.
The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis:basis as of December 31, 2021 and 2020:
| December 31, 2021 | ||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
| Commodity derivative instruments | $— | $1,798 | $— | |||||||||||||||||
| Contingent consideration arrangements | — | 20,833 | — | |||||||||||||||||
| Liabilities | ||||||||||||||||||||
Commodity derivative instruments (1) | — | (172,386) | — | |||||||||||||||||
| Contingent consideration arrangements | — | (25,000) | — | |||||||||||||||||
| Total net assets (liabilities) | $— | ($174,755) | $— | |||||||||||||||||
| December 31, 2020 | ||||||||||||||||||||
| Level 1 | Level 2 | Level 3 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Assets | ||||||||||||||||||||
| Commodity derivative instruments | $— | $921 | $— | |||||||||||||||||
| Contingent consideration arrangements | — | 1,816 | — | |||||||||||||||||
| Liabilities | ||||||||||||||||||||
Commodity derivative instruments (2) | — | (97,060) | — | |||||||||||||||||
| Contingent consideration arrangements | — | (8,618) | — | |||||||||||||||||
| September 2020 Warrants | — | — | (79,428) | |||||||||||||||||
| Total net assets (liabilities) | $— | ($102,941) | ($79,428) | |||||||||||||||||
(1) Includes approximately $2.9 million of deferred premiums which will be paid as the applicable contracts settle.
(2) Includes approximately $11.2 million of deferred premiums which will be paid as the applicable contracts settle.
September 2020 Warrants. The fair value of the September 2020 Warrants was calculated using a Black Scholes-Merton option pricing model. As historical volatility is a significant input into the model, the September 2020 Warrants were designated as Level 3 within the valuation hierarchy.
In February 2021, holders of the September 2020 Warrants provided notice and exercised all of their outstanding warrants. The exercise of the September 2020 Warrants resulted in settlement of the associated derivative liability of $134.8 million. See “Note 7 - Borrowings” and “Note 8 - Derivative Instruments and Hedging Activities” for additional details regarding the September 2020 Warrants.
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| December 31, 2017 | Classification | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets | |||||||||||||||||
| Derivative financial instruments | Fair value of derivatives | $ | — | $ | 406 | $ | — | $ | 406 | ||||||||
| Liabilities | |||||||||||||||||
| Derivative financial instruments | Fair value of derivatives | — | (29,028 | ) | — | (29,028 | ) | ||||||||||
| Total net liabilities | $ | — | $ | (28,622 | ) | $ | — | $ | (28,622 | ) | |||||||
| | |||||||||||||||||
| December 31, 2016 | Classification | Level 1 | Level 2 | Level 3 | Total | ||||||||||||
| Assets | |||||||||||||||||
| Derivative financial instruments | Fair value of derivatives | $ | — | $ | 103 | $ | — | $ | 103 | ||||||||
| Liabilities | |||||||||||||||||
| Derivative financial instruments | Fair value of derivatives | — | (18,296 | ) | — | (18,296 | ) | ||||||||||
| Total net liabilities | $ | — | $ | (18,193 | ) | $ | — | $ | (18,193 | ) | |||||||
The following table presents a reconciliation of the change in the fair value of the liability related to the September 2020 Warrants, which was designated as Level 3 within the valuation hierarchy, for the years ended December 31, 2021 and 2020.
| Years Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Beginning of period | $79,428 | $— | ||||||||||||
| Recognition of issuance date fair value | — | 23,909 | ||||||||||||
(Gain) loss on changes in fair value (1) | 55,390 | 55,519 | ||||||||||||
| Transfers into (out of) Level 3 | (134,818) | — | ||||||||||||
| End of period | $— | $79,428 | ||||||||||||
(1) Included in “(Gain) loss on derivative contracts” in the consolidated statements of operations.
Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis
Acquisitions. The Company determines the fair value of the assets acquired and liabilities assumed, other than the contingent consideration arrangements which are discussed above, are measured as of the acquisition date by a third-party valuation specialist using a combination of income and market approaches, which are not observable in the income approach based onmarket and are therefore designated as Level 3 inputs. Significant inputs include expected discounted future cash flows from estimated reserve quantities, estimates for timing and costs to produce and develop reserves, and oil and natural gas forward prices. The future net revenues are discounted usingprices, and a weighted average cost of capital. The discounted future net revenues of proved undevelopedrisk adjusted discount rate. See “Note 4 - Acquisitions and probable reserves are reduced by anDivestitures” for additional reserve adjustment factor to compensate for the inherent risk of estimating the value of unevaluated properties. The fair value measurements were based on Level 1, Level 2 and Level 3 inputs.discussion.
Asset Retirement Obligations.The Company utilizes various forms of incentive compensation designed to align the interest of the executives and employees with those of its stockholders. Tabular disclosures related to the share-based awards are presented in Note 9. The narrative that follows provides a brief description of each plan, summarizes the overall status of each plan and discusses current year awards under each plan:
Note 9 - 10 – Share-Based Compensation
2020 Omnibus Incentive Plan
RSU Equity Awards
The following table summarizes RSU Equity Award activity for the year ended December 31, 2021:
| RSU Equity Awards (in thousands) | Weighted Average Grant-Date Fair Value per Share | |||||||||||||
| Unvested at the beginning of the year | 677 | $34.57 | ||||||||||||
| Granted | 643 | $38.59 | ||||||||||||
| Vested | (224) | $43.97 | ||||||||||||
| Forfeited | (128) | $42.40 | ||||||||||||
| Unvested at the end of the year | 968 | $34.04 | ||||||||||||
Grant activity for the year ended December 31, 2021, 2020 and 2019 primarily consisted of RSU Equity Awards granted to executives and employees as part of the annual grant of long-term equity incentive awards with a weighted average grant date fair value of $38.59, $21.07 and $85.96, respectively.
For outstanding performance-based RSU Equity Awards, the number of performance-based RSU Equity Awards that can vest is based on a calculation that compares the Company’s only active plan,total shareholder return (“TSR”) to the 2011 Plan, were 1,338,356. same calculated return of a group of peer companies selected by the Company and can range between 0% and 300% of the target units for the awards granted in 2020 and between 0% and 200% of the target units for the awards granted in 2019. The increase in the maximum amount of performance-based RSU Equity Awards that can vest for the awards granted in 2020 is due to an absolute TSR modifier, which was added as a second factor in the calculation, in addition to the relative TSR multiplier. While the absolute TSR modifier could increase the number of
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awards that vest, the number of awards that vest could also be reduced if the absolute TSR is less than 5% over the performance period. No performance-based RSU Equity Awards were granted during 2021.
The following table summarizes the shares that vested and did not vest as a result of the Company’s performance as compared to its peers.
| Years Ended December 31, | ||||||||||||||||||||
| Performance-based Equity Awards | 2021 | 2020 | 2019 | |||||||||||||||||
| Vesting Multiplier | 50 | % | 50% - 100% | 100 | % | |||||||||||||||
| Target | 28,356 | 21,920 | 8,878 | |||||||||||||||||
| Vested at end of performance period | 14,177 | 11,372 | 8,878 | |||||||||||||||||
| Did not vest at end of performance period | 14,179 | 10,548 | — | |||||||||||||||||
The Company recognizes expense for performance-based RSU Equity Awards based on the fair value of the awards at the grant date. Awards with a performance-based provision do not allow for the reversal of previously recognized expense, even if the market metric is not achieved and no shares ultimately vest. For the years ended December 31, 2020 and 2019, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $3.4 million and $4.3 million, respectively. The following table summarizes the assumptions used and the resulting grant date fair value per performance-based RSU Equity Award granted during the years ended December 31, 2020 and 2019:
| Performance-based Awards | June 29, 2020 | January 31, 2020 | January 31, 2019 | |||||||||||||||||
| Expected term (in years) | 2.5 | 2.9 | 2.9 | |||||||||||||||||
| Expected volatility | 113.2 | % | 54.8 | % | 47.9 | % | ||||||||||||||
| Risk-free interest rate | 0.2 | % | 1.3 | % | 2.4 | % | ||||||||||||||
| Dividend yield | — | % | — | % | — | % | ||||||||||||||
The aggregate fair value of RSU Equity Awards that vested during the years ended December 31, 2021, 2020 and 2019 was $8.7 million, $1.6 million and $7.3 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested RSU Equity Awards were $21.2 million and will be recognized over a weighted average period of 2.0 years.
Cash-Settled Awards
Cash-Settled RSU Awards. The table below summarizes the Cash-Settled RSU Award activity for the year ended December 31, 2021:
| Cash-Settled RSU Awards (in thousands) | Weighted Average Grant-Date Fair Value per Share | |||||||||||||
| Unvested at the beginning of the year | 196 | $47.56 | ||||||||||||
Granted (1) | 3 | $36.71 | ||||||||||||
| Vested | (14) | $107.93 | ||||||||||||
| Did not vest at end of performance period | (14) | $107.93 | ||||||||||||
| Forfeited | (24) | $54.57 | ||||||||||||
| Unvested at the end of the year | 147 | $34.60 | ||||||||||||
(1)Includes 3.2 thousand units associated with deferrals of certain non-employee director compensation pursuant to the terms of the Amended and Restated Deferred Compensation Plan for Outside Directors.
No Cash-Settled RSU Awards were granted to employees during the year ended December 31, 2021. Grant activity during the years ended December 31, 2020 and 2019 primarily consisted of Cash-Settled RSU Awards to executives as part of the annual grant of long-term equity incentive awards. These awards cliff vest after an approximate three-year performance period. The weighted average grant date fair value of Cash-Settled RSU Awards was $36.71, $26.84 and $105.08 for the years ended December 31, 2021, 2020 and 2019, respectively.
The Company’s outstanding Cash-Settled RSU Awards include the same performance-based vesting conditions as the performance-based RSU Equity Awards, which are described above. Additionally, the assumptions used to calculate the grant date fair value per Cash-Settled RSU Award granted during the years ended December 31, 2020 and 2019 are the same as the performance-based RSU Equity Awards presented above.
For the years ended December 31, 2021, 2020 and 2019, Cash-Settled RSU Awards vested resulting in cash payments of $0.7 million, $0.2 million and $0.8 million, respectively. As of December 31, 2021, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $2.7 million and will be recognized over a weighted average period of 1.0 years.
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Cash-Settled SARs. The table below summarizes the Cash SAR activity for the year ended December 31, 2021.
| Stock Appreciation Rights (in thousands) | Weighted Average Exercise Prices | Weighted Average Remaining Life (In years) | Aggregate Intrinsic Value (In millions) | |||||||||||||||||||||||
| Outstanding, beginning of the year | 368 | $100.34 | ||||||||||||||||||||||||
| Granted | — | $— | ||||||||||||||||||||||||
| Exercised | — | $— | ||||||||||||||||||||||||
| Forfeited | — | $— | ||||||||||||||||||||||||
| Expired | (65) | $156.00 | ||||||||||||||||||||||||
| Outstanding, end of the year | 303 | $88.37 | 3.1 | $— | ||||||||||||||||||||||
| Vested, end of the year | 303 | $88.37 | — | $— | ||||||||||||||||||||||
| Vested and exercisable, end of the year | — | $— | — | $— | ||||||||||||||||||||||
As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2021. The acquisition date fair value of the Cash SARs in 2019, calculated using the Black-Scholes-Merton option pricing model, was $4.6 million. The following table summarizes the assumptions used and the expiration date for the grants that occurred during the period presented below:
| Cash SARs | 2019 | |||||||||||||||||||||||||
| Expected term (in years) | 5.4 | |||||||||||||||||||||||||
| Expected volatility | 60.7 | % | ||||||||||||||||||||||||
| Risk-free interest rate | 1.7 | % | ||||||||||||||||||||||||
| Dividend yield | — | % | ||||||||||||||||||||||||
| Expiration date | March 17, 2026 | |||||||||||||||||||||||||
The following table summarizes the classification in the consolidated balance sheets of the Company’s cash-settled awards for the periods indicated:
| December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Cash SARs | $7,884 | $1,670 | ||||||||||||
| Cash-Settled RSU Awards | 1,382 | 182 | ||||||||||||
| Other current liabilities | 9,266 | 1,852 | ||||||||||||
| Cash-Settled RSU Awards | 6,366 | 1,336 | ||||||||||||
| Other long-term liabilities | 6,366 | 1,336 | ||||||||||||
| Total Cash-Settled RSU Awards | $15,632 | $3,188 | ||||||||||||
Share-Based Compensation Expense, Net
Share-based compensation expense associated with the RSU Equity Awards, Cash-Settled RSU Awards, and Cash SARs, net of amounts capitalized, is included in “General and administrative” in the consolidated statements of operations. The following table presents share-based compensation expense (benefit), net for each respective period:
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| RSU Equity Awards | $13,230 | $13,030 | $14,322 | |||||||||||||||||
| Cash-Settled RSU Awards | 6,412 | (771) | 1,021 | |||||||||||||||||
| Cash SARs | 6,215 | (3,344) | 443 | |||||||||||||||||
| 25,857 | 8,915 | 15,786 | ||||||||||||||||||
| Less: amounts capitalized to oil and gas properties | (12,934) | (6,252) | (4,704) | |||||||||||||||||
| Total share-based compensation expense, net | $12,923 | $2,663 | $11,082 | |||||||||||||||||
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| | For the Year Ended December 31, | ||||||||||||||||||||||
| | 2017 | 2016 | 2015 | ||||||||||||||||||||
| Share-based compensation cost for: | Equity-based | Liability-based | Equity-based | Liability-based | Equity-based | Liability-based | |||||||||||||||||
RSU equity awards (a) | $ | 10,225 | $ | — | $ | 4,536 | $ | — | $ | 3,797 | $ | — | |||||||||||
Cash-settleable RSU awards (a) | — | 4,294 | — | 12,285 | — | 11,437 | |||||||||||||||||
| 401(k) CPE stock fund contributions | 313 | — | 277 | — | 266 | — | |||||||||||||||||
Total share-based compensation cost (b) | $ | 10,538 | $ | 4,294 | $ | 4,813 | $ | 12,285 | $ | 4,063 | $ | 11,437 | |||||||||||
| | December 31, | |||||||||||
| Unrecognized compensation cost related to: | 2017 | 2016 | 2015 | |||||||||
| Unvested RSU equity awards | $ | 13,158 | $ | 7,276 | $ | 5,208 | ||||||
| Unvested cash-settleable RSU awards | 3,776 | 8,948 | 4,728 | |||||||||
| | December 31, | |||||||
| Consolidated Balance Sheets Classification | 2017 | 2016 | ||||||
| Cash-settled RSU awards (current) | $ | 4,621 | $ | 8,919 | ||||
| Cash-settled RSU awards (non-current) | 3,490 | 8,071 | ||||||
| Total cash-settled RSU awards | $ | 8,111 | $ | 16,990 | ||||
Note 11– Stockholders’ Equity
On November 3, 2021, at a special meeting of shareholders, the Company obtained the requisite shareholder approval for the issuance
of approximately 5.5 million shares of the Company’s common stock in exchange for an aggregate of $197.0 million principal amount of Second Lien Notes. The Exchange was completed on November 5, 2021 and the exchanged Second Lien Notes were immediately cancelled. See “Note 7 - Borrowings” for discussion of the exchange of Second Lien Notes for Company common stock.
Primexx Acquisition
During the fourth quarter of 2021, the Company issued approximately 9.0 million shares of common stock in connection with the Primexx Acquisition, inclusive of the shares of common stock issued to those certain interest owners who exercised their option to sell their interest in the properties included in the Primexx Acquisition. See “Note 4 - Acquisitions and Divestitures” for additional details.
November 2020 Warrants
The following table represents unvested restricted stock activityCompany issued approximately 1.75 million November 2020 Warrants in conjunction with the November 2020 Second Lien Notes that were issued in the senior unsecured note exchange described above. The Company determined that the November 2020 Warrants qualify as freestanding financial instruments, but meet the scope exception in ASC 815 - Derivatives and Hedging as they are indexed to the Company’s common stock. As such, the November 2020 Warrants meet the applicable criteria for equity classification and are reflected in additional paid in capital in the consolidated balance sheets. See “Note 7 - Borrowings” for additional information.
Warrant Exercises
During the year ended December 31, 2017:
| | Weighted average | ||||||||
| (shares in 000s) | Number of Shares | Grant-Date Fair Value per Share | Years Over Which Expense is Expected to be Recognized | ||||||
| Outstanding at the beginning of the period | 1,448 | $ | 10.81 | ||||||
Granted (a)(b) | 1,173 | 12.25 | |||||||
Vested (b)(c) | (797 | ) | 11.35 | ||||||
| Forfeited | (34 | ) | 9.57 | ||||||
| Outstanding at the end of the period | 1,790 | $ | 11.54 | 1.94 | |||||
September 2020 Warrants. As of December 31, 2017,2021, no September 2020 or November 2020 Warrants were outstanding.
Increase in Authorized Common Shares
The Company filed an amendment to its certificate of incorporation, which became effective on May 14, 2021, to increase the Company hadnumber
of authorized shares of common stock from 52,500,000 to 78,750,000, as approved by the following cash-settleable RSUs outstanding (including those that are not basedCompany’s shareholders at the 2021 Annual Meeting of Shareholders on May 14, 2021.
Reverse Stock Split
On August 7, 2020, the Board of Directors effected a market condition):
| (shares in 000s) | Base Units Outstanding | Potential Minimum Units Vesting | Potential Maximum Units Vesting | ||||||
| Vesting in 2018 | 165 | 13 | 316 | ||||||
| Vesting in 2019 | 200 | 17 | 384 | ||||||
| Vesting in 2020 | — | — | — | ||||||
| Other | 203 | 203 | 203 | ||||||
| Total cash-settleable RSUs | 568 | 233 | 903 | ||||||
give effect to this reverse stock split.
10% Series A Cumulative Preferred Stock (“Preferred Stock”)
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Note 12 – Income Taxes
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Current | ||||||||||||||||||||
| Federal | $— | $— | $— | |||||||||||||||||
| State | 180 | 3,447 | 220 | |||||||||||||||||
| Total current income tax expense | 180 | 3,447 | 220 | |||||||||||||||||
| Deferred | ||||||||||||||||||||
| Federal | — | 126,903 | 33,584 | |||||||||||||||||
| State | — | (8,296) | 1,497 | |||||||||||||||||
| Total deferred income tax expense | — | 118,607 | 35,081 | |||||||||||||||||
| Total income tax expense | $180 | $122,054 | $35,301 | |||||||||||||||||
A reconciliation of the common stock onincome tax expense calculated at the datefederal statutory rate of the change21% to income tax expense is as follows:
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Income (loss) before income taxes | $365,331 | ($2,411,567) | $103,229 | |||||||||||||||||
| Income tax expense (benefit) computed at the statutory federal income tax rate | 76,720 | (506,429) | 21,678 | |||||||||||||||||
| State income tax expense (benefit), net of federal benefit | 2,905 | (11,827) | 1,253 | |||||||||||||||||
| Non-deductible expenses related to capital structure transactions | (11,875) | — | — | |||||||||||||||||
| Non-deductible compensation | 1,100 | — | 90 | |||||||||||||||||
| Equity based compensation | 564 | 2,746 | 1,222 | |||||||||||||||||
| Non-deductible merger expenses | — | — | 5,537 | |||||||||||||||||
| Statutory depletion carryforward | — | — | 5,381 | |||||||||||||||||
| Other | 9,147 | (1,621) | 140 | |||||||||||||||||
| Change in valuation allowance | (78,381) | 639,185 | — | |||||||||||||||||
| Income tax expense | $180 | $122,054 | $35,301 | |||||||||||||||||
The income tax expense of control as determined under the certificate of designations$0.2 million for the Preferred Stock. If the change of control occurred onyear ended December 31, 2017, and2021 is primarily due to the Company did not exercise its right to redeem the Preferred Stock, using the closing price of $12.15 as the value of a share of common stock, each share of Preferred Stock would be convertible into approximately 4.1 shares of common stock. If the Company exercises its redemption rights relating to shares of Preferred Stock, the holders of Preferred Stock will not have the conversion right described above.
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| | As of December 31, | |||||||
| | 2017 | 2016 | ||||||
Deferred tax asset (a) | ||||||||
Federal net operating loss carryforward (b) | $ | 97,437 | $ | 135,711 | ||||
| Statutory depletion carryforward | 5,381 | 8,843 | ||||||
Alternative minimum tax credit carryforward (c) | 52 | 104 | ||||||
| Asset retirement obligations | 572 | 1,181 | ||||||
| Derivatives | 6,186 | 6,456 | ||||||
| Unvested RSU equity awards | 1,749 | 2,092 | ||||||
| Other | 2,401 | 4,376 | ||||||
| Deferred tax asset before valuation allowance | 113,778 | 158,763 | ||||||
Deferred tax liability (a) | ||||||||
| Oil and natural gas properties | 54,264 | 18,661 | ||||||
| Total deferred tax liability | 54,264 | 18,661 | ||||||
| Net deferred tax asset before valuation allowance | 59,514 | 140,102 | ||||||
| Less: Valuation allowance | (60,919 | ) | (140,192 | ) | ||||
| Net deferred tax liability | $ | (1,405 | ) | $ | (90 | ) | ||
| As of December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Deferred tax assets | ||||||||||||||
| Oil and natural gas properties | $238,203 | $431,142 | ||||||||||||
| Federal net operating loss carryforward | 221,900 | 141,308 | ||||||||||||
| Net interest expense limitation | 36,171 | — | ||||||||||||
| Derivative asset | 30,826 | 39,378 | ||||||||||||
| Operating lease right-of-use assets | 8,650 | 8,567 | ||||||||||||
| Asset retirement obligations | 12,244 | 10,134 | ||||||||||||
| Unvested RSU equity awards | 4,939 | 1,962 | ||||||||||||
| Other | 12,892 | 11,430 | ||||||||||||
| Total deferred tax assets | $565,825 | $643,921 | ||||||||||||
| Deferred income tax valuation allowance | (560,804) | (639,185) | ||||||||||||
| Net deferred tax assets | $5,021 | $4,736 | ||||||||||||
| Deferred tax liability | ||||||||||||||
| Operating lease liabilities | ($5,021) | ($4,736) | ||||||||||||
| Total deferred tax liability | ($5,021) | ($4,736) | ||||||||||||
| Net deferred tax asset (liability) | $— | $— | ||||||||||||
Deferred Tax Reform, will expire as follows:Asset Valuation Allowance
| | Year Expiring | |||||||||||||||||||||||
| | Total | 2018-2023 | 2024-2026 | 2027-2029 | 2030-2032 | 2033-2037 | ||||||||||||||||||
| Federal NOL carryforwards | $ | 463,985 | $ | 111,431 | $ | 14,408 | $ | 41,379 | $ | 42,158 | $ | 254,609 | ||||||||||||
The Company will continue to evaluate whether the valuation allowance is needed in future reporting periods. The valuation allowance will remain until the Company can conclude that the net deferred tax assets are more likely than not to be realized. Future events or new evidence which may lead the Company to conclude that it is more likely than not its net deferred tax assets will be realized include, but are not limited to, cumulative historical pre-tax earnings, improvements in crude oil prices, and taxable events that could result from one or more future potential transactions. The valuation allowance does not preclude the Company from utilizing the tax attributes if the Company recognizes taxable income. As long as the Company continues to conclude that the valuation allowance against its net deferred tax assets is necessary, the Company will have no significant deferred income tax expense or benefit.
Federal Net Operating Losses (“NOLs”) & Interest Limitation Carryforwards
Due to the issuance of common stock associated with the Carrizo Acquisition, the Company incurred a cumulative three year loss. Becauseownership change and as such, the Company’s NOLs prior to the acquisition are subject to an annual limitation under Internal Revenue Code Section 382. At December 31, 2021, the Company had approximately $1.1 billion of NOLs of which $414.9 million expire between 2035 and 2037 and $641.8 million have an indefinite carryforward life. The Company also has a net interest expense carryforward of $172.2 million under Section 163(j) of the impact the cumulative loss has on the determination of the recoverability of deferred tax assets through future earnings, the Company assessed the abilityCode, subject to realize its deferred tax assets based on the future reversals of existing deferred tax liabilities. Accordingly, the Company established a valuation allowance for a portion of the deferred tax asset. The valuation allowance was $60,919 as of December 31, 2017.indefinite carryforward.
Uncertain Tax Positions
The Company had no significant unrecognized tax benefits at December 31, 2017.2021. Accordingly, the Company does not have any interest or penalties related to uncertain tax positions. However, if interest or penalties were to be incurred related to uncertain tax positions, such amounts would be recognized in income tax expense. Tax periods for years 2004 through 2017 remainIn the Company’s major tax jurisdictions, the earliest year open to examination by the federal and state taxing jurisdictions to which the Company is subject.2017.
Note 13 – Leases
The Company providescurrently has leases associated with contracts for income taxes at a statutory rateoffice space, drilling rigs, and the use of 35% adjusted for permanent differences expected to be realized,well equipment, vehicles, information technology infrastructure, and other office equipment. The tables below, which primarily relate to non-deductible executive compensation expenses, restricted stock windfalls,present the components of lease costs and state income taxes. The following table presents a reconciliation of the reported amount of income tax expense to the amount of income tax expense that would result from applying domestic federal statutory tax rates to pretax income from continuing operations:
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supplemental balance sheet information are presented on a gross basis. Other joint owners in the properties operated by the Company generally pay for their working interest share of costs associated with drilling rigs and well equipment.
The table below presents the components of the Company’s lease costs for the year ended December 31, 2021.
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Components of Lease Costs | ||||||||||||||||||||
| Finance lease costs | $277 | $1,489 | $92 | |||||||||||||||||
Amortization of right-of-use assets (1) | 237 | 1,348 | 82 | |||||||||||||||||
Interest on lease liabilities (2) | 40 | 141 | 10 | |||||||||||||||||
Operating lease cost (3) | 37,734 | 46,888 | 38,076 | |||||||||||||||||
Impairment of Operating lease ROU assets (4) | — | 3,575 | 16,209 | |||||||||||||||||
Short-term lease cost (5) | 347 | 1,821 | 3,640 | |||||||||||||||||
Variable lease costs (6) | 284 | 259 | — | |||||||||||||||||
| Total lease costs | $38,642 | $54,032 | $58,017 | |||||||||||||||||
(1)Included as a component of “Depreciation, depletion and amortization” in the consolidated statements of operations.
(2)Included as a component of “Interest expense, net of capitalized amounts” in the consolidated statements of operations.
(3)For the years ended December 31, 2021, 2020 and 2019, approximately $23.0 million, $34.2 million and $34.9 million, respectively, are costs associated with drilling rigs. These costs were capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs were components of “General and administrative” and “Lease operating” in the consolidated statements of operations.
(4)As a result of the downturn in economic conditions in conjunction with the Company’s ongoing effort to consolidate various office locations due to the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment. Upon evaluation, the Company recorded impairments of certain of its Operating lease ROU assets for the years ended December 31, 2021, 2020 and 2019 of zero, $3.6 million and $16.2 million, respectively, which are a component of “Merger and integration expenses” in the consolidated statements of operations.
(5)Short-term lease cost excludes expenses related to leases with a contract term of one month or less.
(6)Variable lease costs include additional payments that were not included in the initial measurement of the lease liability and related ROU asset for lease agreements with terms greater than 12 months. Variable lease costs primarily consist of incremental usage associated with drilling rigs.
The table below presents supplemental balance sheet information for the Company’s operating leases. The Company’s financing leases are immaterial.
| As of December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Leases | ||||||||||||||
| Operating leases: | ||||||||||||||
| Operating lease ROU assets | $23,884 | $22,526 | ||||||||||||
| Current operating lease liabilities | $17,599 | $13,175 | ||||||||||||
| Long-term operating lease liabilities | 23,547 | 27,576 | ||||||||||||
| Total operating lease liabilities | $41,146 | $40,751 | ||||||||||||
The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2021.
| December 31, 2021 | |||||||||||||||||
| Weighted Average Remaining Lease Terms (In years) | |||||||||||||||||
| Operating leases | 5.1 | ||||||||||||||||
| Financing leases | 2.2 | ||||||||||||||||
| Operating leases | 5.6 | % | |||||||||||||||
| Financing leases | 6.6 | % | |||||||||||||||
91
| | For the Year Ended December 31, | ||||||||
| Components of income tax rate reconciliation | 2017 | 2016 | 2015 | ||||||
| Income tax expense computed at the statutory federal income tax rate | 35 | % | 35 | % | 35 | % | |||
| State taxes net of federal benefit | 1 | % | — | % | 1 | % | |||
| Section 162(m) | — | % | (1 | )% | (1 | )% | |||
| Valuation allowance | (35 | )% | (34 | )% | (54 | )% | |||
| Effective income tax rate | 1 | % | — | % | (19 | )% | |||
The table below presents the maturity of the Company’s lease liabilities as of December 31, 2021.
| Operating Leases | Financing Leases | |||||||||||||
| (In thousands) | ||||||||||||||
| 2022 | $18,981 | $250 | ||||||||||||
| 2023 | 5,031 | 233 | ||||||||||||
| 2024 | 4,939 | 39 | ||||||||||||
| 2025 | 3,958 | — | ||||||||||||
| 2026 | 3,805 | — | ||||||||||||
| Thereafter | 10,334 | — | ||||||||||||
| Total lease payments | 47,048 | 522 | ||||||||||||
| Less imputed interest | (5,902) | (36) | ||||||||||||
| Total lease liabilities | $41,146 | $486 | ||||||||||||
| | For the Year Ended December 31, | |||||||||||
| Components of income tax expense | 2017 | 2016 | 2015 | |||||||||
| Current federal income tax benefit | $ | (48 | ) | $ | (104 | ) | $ | — | ||||
| Deferred federal income tax benefit | (45 | ) | — | (69,087 | ) | |||||||
| Deferred state income tax (benefit) expense | 1,366 | 90 | (1,282 | ) | ||||||||
| Valuation allowance | — | — | 108,843 | |||||||||
| Total income tax (benefit) expense | $ | 1,273 | $ | (14 | ) | $ | 38,474 | |||||
Note 12-14– Asset Retirement Obligations
The table below summarizes the activity for the Company’s asset retirement obligations:
| Years Ended December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| (In thousands) | ||||||||||||||
| Asset retirement obligations, beginning of period | $59,090 | $49,733 | ||||||||||||
| Accretion expense | 3,743 | 3,323 | ||||||||||||
| Liabilities incurred | 1,826 | 3,895 | ||||||||||||
| Increase due to acquisition of oil and gas properties | 1,898 | — | ||||||||||||
| Liabilities settled | (1,769) | (2,220) | ||||||||||||
| Dispositions | (7,262) | (351) | ||||||||||||
| Revisions to estimates | (819) | 4,710 | ||||||||||||
| Asset retirement obligations, end of period | 56,707 | 59,090 | ||||||||||||
| Less: Current asset retirement obligations | (2,249) | (1,881) | ||||||||||||
| Non-current asset retirement obligations | $54,458 | $57,209 | ||||||||||||
| | For the Year Ended December 31, | |||||||
| | 2017 | 2016 | ||||||
| Asset retirement obligations at January 1, 2017 and 2016, respectively | $ | 6,661 | $ | 5,107 | ||||
| Accretion expense | 677 | 958 | ||||||
| Liabilities incurred | 278 | 84 | ||||||
| Liabilities settled | (711 | ) | (2,378 | ) | ||||
Revisions to estimate (a) | (885 | ) | 2,890 | |||||
| Asset retirement obligations at end of period | 6,020 | 6,661 | ||||||
| Less: Current asset retirement obligations | (1,295 | ) | (2,729 | ) | ||||
| Long-term asset retirement obligations at December 31, 2017 and 2016, respectively | $ | 4,725 | $ | 3,932 | ||||
Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the Consolidated Balance Sheetsconsolidated balance sheets at December 31, 20172021 and 20162020 as long-term restricted investments were $3,3723.5 million, and $3,332, respectively.are presented in “Other assets, net.” These assets, which primarily include short-term U.S. Government securities, are held in abandonment trusts dedicated to pay future abandonment costs for several of the Company’s oil and natural gas properties.
Note 15 – Accounts Receivable, Net
| As of December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Oil and natural gas receivables | $171,837 | $100,257 | |||||||||
| Joint interest receivables | 13,751 | 11,530 | |||||||||
| Other receivables | 49,053 | 24,191 | |||||||||
| Total | 234,641 | 135,978 | |||||||||
| Allowance for credit losses | (2,205) | (2,869) | |||||||||
| Total accounts receivable, net | $232,436 | $133,109 | |||||||||
Note 16 – Accounts Payable and Accrued Liabilities
| As of December 31, | |||||||||||
| 2021 | 2020 | ||||||||||
| (In thousands) | |||||||||||
| Accounts payable | $151,836 | $101,231 | |||||||||
| Revenues and royalties payable | 294,143 | 162,762 | |||||||||
| Accrued capital expenditures | 64,412 | 32,493 | |||||||||
| Accrued interest | 59,600 | 45,033 | |||||||||
| Total accounts payable and accrued liabilities | $569,991 | $341,519 | |||||||||
92
Note 1317–Supplemental Information on Oil and Natural Gas Operations (Unaudited)
| | For the Year Ended December 31, | |||||||||||
| | 2017 | 2016 | 2015 | |||||||||
Evaluated Properties (a) | ||||||||||||
| Beginning of period balance | $ | 2,754,353 | $ | 2,335,223 | $ | 2,077,985 | ||||||
| Capitalized G&A expenses | 11,982 | 12,222 | 10,529 | |||||||||
Property acquisition costs (b) | 144,358 | 216,561 | 26,726 | |||||||||
| Exploration costs | 239,453 | 38,612 | 81,320 | |||||||||
| Development costs | 279,424 | 151,735 | 138,663 | |||||||||
| End of period balance | $ | 3,429,570 | $ | 2,754,353 | $ | 2,335,223 | ||||||
Unevaluated Properties (a)(c) | ||||||||||||
| Beginning of period balance | $ | 668,721 | $ | 132,181 | $ | 142,525 | ||||||
Property acquisition costs (b) | 590,308 | 548,673 | 5,520 | |||||||||
| Exploration costs | 6,374 | 8,631 | 4,576 | |||||||||
| Capitalized interest expenses | 33,783 | 19,857 | 10,459 | |||||||||
| Transfers to Evaluated Properties | (131,170 | ) | (40,621 | ) | (30,899 | ) | ||||||
| End of period balance | $ | 1,168,016 | $ | 668,721 | $ | 132,181 | ||||||
| Accumulated depreciation, depletion and amortization | ||||||||||||
| Beginning of period balance | $ | 1,947,673 | $ | 1,756,018 | $ | 1,478,355 | ||||||
| Provision charged to expense | 115,897 | 71,330 | 69,228 | |||||||||
Write-down of oil and natural gas properties (a) | — | 95,788 | 208,435 | |||||||||
Sale of mineral interests and equipment (a) | 20,525 | 24,537 | — | |||||||||
| End of period balance | $ | 2,084,095 | $ | 1,947,673 | $ | 1,756,018 | ||||||
| | For the Year Ended December 31, | ||||||||
| Proved developed and undeveloped reserves: | 2017 | 2016 | 2015 | ||||||
| Oil (MBbls): | |||||||||
| Beginning of period | 71,145 | 43,348 | 25,733 | ||||||
| Revisions to previous estimates | (5,171 | ) | (5,738 | ) | (1,632 | ) | |||
| Purchase of reserves in place | 8,388 | 25,054 | 2,932 | ||||||
| Sale of reserves in place | — | (1,718 | ) | (23 | ) | ||||
| Extensions and discoveries | 39,267 | 14,479 | 19,127 | ||||||
| Production | (6,557 | ) | (4,280 | ) | (2,789 | ) | |||
| End of period | 107,072 | 71,145 | 43,348 | ||||||
| Natural Gas (MMcf): | |||||||||
| Beginning of period | 122,611 | 65,537 | 42,548 | ||||||
| Revisions to previous estimates | 6,336 | 13,929 | 4,870 | ||||||
| Purchase of reserves in place | 12,711 | 36,474 | 2,915 | ||||||
| Sale of reserves in place | — | (2,765 | ) | (105 | ) | ||||
| Extensions and discoveries | 48,648 | 17,194 | 19,621 | ||||||
| Production | (10,896 | ) | (7,758 | ) | (4,312 | ) | |||
| End of period | 179,410 | 122,611 | 65,537 | ||||||
| | For the Year Ended December 31, | ||||||||
| Proved developed reserves: | 2017 | 2016 | 2015 | ||||||
| Oil (MBbls): | |||||||||
| Beginning of period | 32,920 | 22,257 | 14,006 | ||||||
| End of period | 51,920 | 32,920 | 22,257 | ||||||
| Natural gas (MMcf): | |||||||||
| Beginning of period | 61,871 | 38,157 | 25,171 | ||||||
| End of period | 104,389 | 61,871 | 38,157 | ||||||
| MBOE: | |||||||||
| Beginning of period | 43,232 | 28,617 | 18,201 | ||||||
| End of period | 69,318 | 43,232 | 28,617 | ||||||
| Proved undeveloped reserves: | |||||||||
| Oil (MBbls): | |||||||||
| Beginning of period | 38,225 | 21,091 | 11,727 | ||||||
| End of period | 55,152 | 38,225 | 21,091 | ||||||
| Natural gas (MMcf): | |||||||||
| Beginning of period | 60,740 | 27,380 | 17,377 | ||||||
| End of period | 75,021 | 60,740 | 27,380 | ||||||
| MBOE: | |||||||||
| Beginning of period | 48,348 | 25,654 | 14,623 | ||||||
| End of period | 67,656 | 48,348 | 25,654 | ||||||
| | 2017 | 2016 | 2015 | |||||||||
Average 12-month price, net of differentials, per Mcf of natural gas (a) | $ | 3.47 | $ | 2.71 | $ | 2.73 | ||||||
Average 12-month price, net of differentials, per barrel of oil (b) | $ | 49.48 | $ | 40.03 | $ | 47.25 | ||||||
| | Standardized Measure | |||||||||||
| | For the Year Ended December 31, | |||||||||||
| | 2017 | 2016 | 2015 | |||||||||
| Future cash inflows | $ | 5,920,328 | $ | 3,180,005 | $ | 2,227,463 | ||||||
| Future costs | ||||||||||||
| Production | (1,692,871 | ) | (974,667 | ) | (827,555 | ) | ||||||
| Development and net abandonment | (680,948 | ) | (384,117 | ) | (239,100 | ) | ||||||
| Future net inflows before income taxes | 3,546,509 | 1,821,221 | 1,160,808 | |||||||||
Future income taxes (a) | (166,985 | ) | (1,602 | ) | — | |||||||
| Future net cash flows | 3,379,524 | 1,819,619 | 1,160,808 | |||||||||
| 10% discount factor | (1,822,842 | ) | (1,009,787 | ) | (589,918 | ) | ||||||
| Standardized measure of discounted future net cash flows | $ | 1,556,682 | $ | 809,832 | $ | 570,890 | ||||||
| | Changes in Standardized Measure | |||||||||||
| | For the Year Ended December 31, | |||||||||||
| | 2017 | 2016 | 2015 | |||||||||
| Standardized measure at the beginning of the period | $ | 809,832 | $ | 570,890 | $ | 579,542 | ||||||
| Sales and transfers, net of production costs | (294,172 | ) | (150,628 | ) | (110,476 | ) | ||||||
| Net change in sales and transfer prices, net of production costs | 176,234 | (103,136 | ) | (286,660 | ) | |||||||
| Net change due to purchases and sales of in place reserves | 129,454 | 260,859 | 37,616 | |||||||||
| Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 635,000 | 180,228 | 184,469 | |||||||||
| Changes in future development cost | 36,983 | 82,320 | 108,216 | |||||||||
| Revisions of quantity estimates | (79,325 | ) | (35,938 | ) | (12,625 | ) | ||||||
| Accretion of discount | 80,983 | 57,091 | 62,968 | |||||||||
| Net change in income taxes | (20,073 | ) | 16 | 35,407 | ||||||||
| Changes in production rates, timing and other | 81,766 | (51,870 | ) | (27,567 | ) | |||||||
| Aggregate change | 746,850 | 238,942 | (8,652 | ) | ||||||||
| Standardized measure at the end of period | $ | 1,556,682 | $ | 809,832 | $ | 570,890 | ||||||
Commitments and contingencies
Contingencies
The Company is involved in various claims and lawsuits incidental to its business. In the opinion of management, the ultimate liability hereunder, if any, will not have a material adverse effect on the financial position or results of operations of the Company.
The Company’s 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 believes 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 are not expected to have a material effect upon the capital expenditures, earnings or the competitive position of the Company with respect to its existing assets and operations. The Company cannot predict what effect additional regulation or legislation, enforcement policies hereunder, and claims for damages to property, employees, other persons and the environment resulting from the Company’s operations could have on its activities.
The table below presents total minimum commitments associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of oil, natural gas, or produced water to be delivered, as of December 31, 2021.
| 2022 | 2023 | 2024 | 2025 | 2026 | 2027 and Thereafter | Total | ||||||||||||||||||||||||||||||||||||||
| (In thousands) | ||||||||||||||||||||||||||||||||||||||||||||
Operating leases (1) | $5,482 | $5,031 | $4,939 | $3,958 | $3,805 | $10,334 | $33,549 | |||||||||||||||||||||||||||||||||||||
Drilling rig and frac service commitments (2) | 53,473 | — | — | — | — | — | 53,473 | |||||||||||||||||||||||||||||||||||||
Delivery commitments (3) | 11,004 | 11,607 | 12,516 | 12,482 | 12,482 | 27,187 | 87,278 | |||||||||||||||||||||||||||||||||||||
Produced water disposal commitments (4) | 14,447 | 9,664 | 8,532 | 4,509 | 569 | 113 | 37,834 | |||||||||||||||||||||||||||||||||||||
| Total | $84,406 | $26,302 | $25,987 | $20,949 | $16,856 | $37,634 | $212,134 | |||||||||||||||||||||||||||||||||||||
(1)Operating leases primarily consist of contracts for office space.
(2)Drilling rig and frac service commitments represent gross contractual obligations and accordingly, other joint owners in the properties operated by the Company will generally be billed for their working interest share of such costs.
(3)Delivery commitments represent contractual obligations the Company has entered into for certain gathering, processing and transportation service agreements which require minimum volumes of oil or natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any oil or natural gas.
(4)Produced water disposal commitments represent contractual obligations the Company has 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.
Operating leases
Leases
As of December 31, 2017,2021, the Company had contracts for five6 horizontal drilling rigs (the “Cactus Rig 1”, “Cactus Rig 2” “Cactus Rig 3”, “Cactus Rig 4” and “Independence Rig”).rigs. The contract terms will end on various dates between January 2022 and November 2022.
Other Commitments
The following table includes the Company’s current oil sales contracts and firm transportation agreements as amended throughof December 31, 2017,2021:
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)For each of the Cactus Rig 1commitments shown in the table above, the committed barrels may include volumes produced by the Company and Cactus Rig 2 will end in January 2020other third-party working, royalty, and February 2021, respectively. The contract terms, as amended in July 2017,overriding royalty interest owners whose volumes the Company markets on their behalf.
(2)Each of the Cactus Rig 3 that commenced drillingfirm transportation agreements shown in mid-January 2017, will end in July 2018. Effective April 2017,the table above grant the Company entered into a contractaccess to delivery points in several locations along the Gulf Coast.
(3)The committed volumes shown in the table above for this particular firm transportation agreement are average volumes. For the Independence Rig, which commenced drilling in July 2017. The contract terms of August 2020-July 2023, August 2023-July 2027 and August 2027-July 2030, the Independence Rig will end in July 2019. Effective November 2017, the Company entered into a contract for the Cactus Rig 4, which commenced drilling in mid-February 2018. The contract terms of the Cactus 4 Rig will end in February 2020.
committed volumes are 7,500 Bbls/d, 10,000 Bbls/d and 12,500 Bbls/d, respectively.
93
Note 18 -Supplemental Information on Oil and Natural Gas Operations (Unaudited)
Estimated Reserves
For each year in the table below, the estimated proved reserves were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers, with the exception of the estimated proved reserves in 2019 obtained as a result of the Carrizo Acquisition, which were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. The reserves were prepared in accordance with guidelines established by the SEC. Accordingly, the following reserve estimates are based upon existing economic and operating conditions.
There are numerous uncertainties inherent in establishing quantities of proved reserves. The following reserve data represents estimates only, and should not be deemed exact. In addition, the standardized measure of discounted future net cash flows should not be construed as the current market value of the Company’s oil and natural gas properties or the cost that would be incurred to obtain equivalent reserves.
Extrapolation of performance history and material balance estimates were utilized by the Company’s both D&M and Ryder Scott to project future recoverable reserves for the producing properties where sufficient history existed to suggest performance trends and where these methods were applicable to the subject reservoirs. The projections for the remaining producing properties were necessarily based on volumetric calculations and/or analogy to nearby producing completions. Reserves assigned to non-producing zones and undeveloped locations were projected on the basis of volumetric calculations and analogy to nearby production, and to a small extent, horizontal PDP and PUD categories.
The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States:
| Years Ended December 31, | ||||||||||||||||||||
| Proved reserves | 2021 | 2020 | 2019 | |||||||||||||||||
| Oil (MBbls) | ||||||||||||||||||||
| Beginning of period | 289,487 | 346,361 | 180,097 | |||||||||||||||||
| Purchase of reserves in place | 35,045 | — | 183,382 | |||||||||||||||||
| Sales of reserves in place | (24,019) | (9,673) | (17,980) | |||||||||||||||||
| Extensions and discoveries | 22,520 | 25,678 | 45,663 | |||||||||||||||||
| Revisions to previous estimates | (10,514) | (49,336) | (33,136) | |||||||||||||||||
| Production | (22,223) | (23,543) | (11,665) | |||||||||||||||||
| End of period | 290,296 | 289,487 | 346,361 | |||||||||||||||||
| Natural Gas (MMcf) | ||||||||||||||||||||
| Beginning of period | 541,598 | 757,134 | 350,466 | |||||||||||||||||
| Purchase of reserves in place | 73,445 | — | 455,158 | |||||||||||||||||
| Sale of reserves in place | (34,837) | (20,389) | (86,856) | |||||||||||||||||
| Extensions and discoveries | 37,896 | 44,282 | 82,566 | |||||||||||||||||
| Revisions to previous estimates | (3,389) | (198,628) | (24,482) | |||||||||||||||||
| Production | (37,386) | (40,801) | (19,718) | |||||||||||||||||
| End of period | 577,327 | 541,598 | 757,134 | |||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||
| Beginning of period | 96,126 | 67,462 | — | |||||||||||||||||
| Purchase of reserves in place | 10,366 | — | 67,597 | |||||||||||||||||
| Sale of reserves in place | (6,191) | (3,049) | — | |||||||||||||||||
| Extensions and discoveries | 7,345 | 8,349 | — | |||||||||||||||||
| Revisions to previous estimates | (3,103) | 30,214 | — | |||||||||||||||||
| Production | (6,439) | (6,850) | (135) | |||||||||||||||||
| End of period | 98,104 | 96,126 | 67,462 | |||||||||||||||||
| Total (MBoe) | ||||||||||||||||||||
| Beginning of period | 475,879 | 540,012 | 238,508 | |||||||||||||||||
| Purchase of reserves in place | 57,652 | — | 326,838 | |||||||||||||||||
| Sale of reserves in place | (36,015) | (16,120) | (32,456) | |||||||||||||||||
| Extensions and discoveries | 36,180 | 41,407 | 59,424 | |||||||||||||||||
| Revisions to previous estimates | (14,181) | (52,227) | (37,216) | |||||||||||||||||
| Production | (34,894) | (37,193) | (15,086) | |||||||||||||||||
| End of period | 484,621 | 475,879 | 540,012 | |||||||||||||||||
94
| Years Ended December 31, | ||||||||||||||||||||
| Proved developed reserves | 2021 | 2020 | 2019 | |||||||||||||||||
| Oil (MBbls) | ||||||||||||||||||||
| Beginning of period | 128,923 | 152,687 | 92,202 | |||||||||||||||||
| End of period | 162,886 | 128,923 | 152,687 | |||||||||||||||||
| Natural gas (MMcf) | ||||||||||||||||||||
| Beginning of period | 238,119 | 320,676 | 218,417 | |||||||||||||||||
| End of period | 332,266 | 238,119 | 320,676 | |||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||
| Beginning of period | 43,315 | 24,844 | — | |||||||||||||||||
| End of period | 55,720 | 43,315 | 24,844 | |||||||||||||||||
| Total proved developed reserves (MBoe) | ||||||||||||||||||||
| Beginning of period | 211,925 | 230,977 | 128,605 | |||||||||||||||||
| End of period | 273,983 | 211,925 | 230,977 | |||||||||||||||||
| Proved undeveloped reserves | ||||||||||||||||||||
| Oil (MBbls) | ||||||||||||||||||||
| Beginning of period | 160,564 | 193,674 | 87,895 | |||||||||||||||||
| End of period | 127,410 | 160,564 | 193,674 | |||||||||||||||||
| Natural gas (MMcf) | ||||||||||||||||||||
| Beginning of period | 303,479 | 436,458 | 132,049 | |||||||||||||||||
| End of period | 245,061 | 303,479 | 436,458 | |||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||
| Beginning of period | 52,811 | 42,618 | — | |||||||||||||||||
| End of period | 42,384 | 52,811 | 42,618 | |||||||||||||||||
| Total proved undeveloped reserves (MBoe) | ||||||||||||||||||||
| Beginning of period | 263,954 | 309,035 | 109,903 | |||||||||||||||||
| End of period | 210,638 | 263,954 | 309,035 | |||||||||||||||||
| Total proved reserves | ||||||||||||||||||||
| Oil (MBbls) | ||||||||||||||||||||
| Beginning of period | 289,487 | 346,361 | 180,097 | |||||||||||||||||
| End of period | 290,296 | 289,487 | 346,361 | |||||||||||||||||
| Natural gas (MMcf) | ||||||||||||||||||||
| Beginning of period | 541,598 | 757,134 | 350,466 | |||||||||||||||||
| End of period | 577,327 | 541,598 | 757,134 | |||||||||||||||||
| NGLs (MBbls) | ||||||||||||||||||||
| Beginning of period | 96,126 | 67,462 | — | |||||||||||||||||
| End of period | 98,104 | 96,126 | 67,462 | |||||||||||||||||
| Total proved reserves (MBoe) | ||||||||||||||||||||
| Beginning of period | 475,879 | 540,012 | 238,508 | |||||||||||||||||
| End of period | 484,621 | 475,879 | 540,012 | |||||||||||||||||
95
Total Proved Reserves
For the year ended December 31, 2015.2021, the Company’s net increase in proved reserves of 8.7 MMBoe was primarily due to the following:
•Increase of 36.2 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 10.1 MMBoe were proved developed reserves;
◦27.9 MMBoe increase primarily due to the change in 12-Month Average Realized Price of crude oil which increased by approximately 75% as compared to December 31, 2020; offset by
◦13.1 MMBoe reduction due to reductions in anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts.
•Increase of 57.7 MMBoe for purchase of reserves in place associated with the Primexx Acquisition;
•Decrease of 36.0 MMBoe for sales of reserves in place associated with the Western Delaware Basin, Eagle Ford, and Midland non-core asset sales; and
•Decrease of 34.9 MMBoe for production.
For the year ended December 31, 2020, the Company’s net decrease in proved reserves of 64.1 MMBoe was primarily due to the following:
•Increase of 41.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 11.7 MMBoe were proved developed reserves;
•Decrease of 52.2 MMBoe for revisions of previous estimates that were primarily comprised of:
◦26.2 MMBoe reduction due to the change in 12-Month Average Realized Price of crude oil which decreased by approximately 31% as compared to December 31, 2019. Included in the decrease are 2.1 MMBoe associated with proved developed producing wells and 0.8 MMBoe associated with proved undeveloped wells that were no longer economic at December 31, 2020 as a result of the decrease in the 12-Month Average Realized Price of crude oil;
◦24.2 MMBoe reduction due to anticipated hydrocarbon recoveries resulting from observed well performance over longer production timeframes during the testing of various full field development plan concepts;
◦24.0 MMBoe reduction due to PUDs that were removed primarily as a result of changes in anticipated well densities as the Company develops its properties in an effort to increase capital efficiency and cash flow generation;
◦14.7 MMBoe increase due to the volumetric impact from presenting NGLs and natural gas separately due to the modification of certain of the Company’s natural gas processing agreements which allow it to take title to NGLs resulting from the processing of its natural gas subsequent to January 1, 2020. For periods prior to January 1, 2020, except for reserve volumes specifically associated with Carrizo, the Company presented its reserve volumes for NGLs with natural gas;
◦7.5 MMBoe increase due to reduced assumptions for operational expenses as the Company continues to improve its field practices during the integration of the properties acquired from Carrizo;
•Decrease of 16.1 MMBoe for sales of reserves in place primarily associated with the ORRI Transaction and the sale of substantially all of the Company’s non-operated assets; and
•Decrease of 37.2 MMBoe for production.
For the year ended December 31, 2019, the Company’s net increase in proved reserves of 301.5 MMBoe was primarily due to the following:
•Increase of 326.8 MMBoe for purchases of reserves in place related to the acquisition of Carrizo Oil & Gas, Inc. in late 2019;
•Increase of 59.4 MMBoe through extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed reserves;
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| 2017 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| Total revenues | $ | 81,363 | $ | 82,283 | $ | 84,614 | $ | 118,214 | ||||||||
| Income from operations | 32,249 | 23,743 | 31,426 | 54,028 | ||||||||||||
| Net income | 47,129 | 33,390 | 17,081 | 22,824 | ||||||||||||
| Income available to common shares | 45,305 | 31,566 | 15,257 | 21,001 | ||||||||||||
| Income per common share - basic | $ | 0.23 | $ | 0.16 | $ | 0.08 | $ | 0.10 | ||||||||
| Income per common share - diluted | $ | 0.22 | $ | 0.16 | $ | 0.08 | $ | 0.10 | ||||||||
| 2016 | First Quarter | Second Quarter | Third Quarter | Fourth Quarter | ||||||||||||
| Total revenues | $ | 30,698 | $ | 45,145 | $ | 55,927 | $ | 69,081 | ||||||||
Income (loss) from operations (a) | (34,767 | ) | (50,529 | ) | 16,651 | 21,168 | ||||||||||
Net income (loss) (a) | (41,109 | ) | (70,097 | ) | 21,139 | (1,746 | ) | |||||||||
| Income (loss) available to common shares | (42,933 | ) | (71,920 | ) | 19,315 | (3,570 | ) | |||||||||
| Income (loss) per common share - basic | $ | (0.51 | ) | $ | (0.61 | ) | $ | 0.14 | $ | (0.02 | ) | |||||
| Income (loss) per common share - diluted | $ | (0.51 | ) | $ | (0.61 | ) | $ | 0.14 | $ | (0.02 | ) | |||||
•Decrease of 32.5 MMBoe as a result of sales of reserves in place, primarily associated with our Ranger Divestiture which totaled 27.1 MMBoe;
•Decrease of 37.2 MMBoe for revisions of previous estimates that were primarily comprised of:
◦21.7 MMBoe reduction due to the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates, primarily in the Midland Basin, as the Company advances larger scale development concepts across its multi-zone inventory;
◦9.8 MMBoe reduction due to reclassifications of PUDs within the Company’s development plans, primarily related to certain fields within the Company’s Delaware Basin acreage, that were moved outside of the five-year development window primarily driven by the acquisition of Carrizo Oil & Gas, Inc. in December 2019, which afforded us the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency through larger scale development concepts as well as preserve our co-development philosophy to optimize resource capture from multiple zones;
◦5.7 MMBoe reduction due to pricing; and
•Decrease of 15.1 MMBoe for production.
Capitalized Costs
Capitalized costs related to oil and natural gas production activities with applicable accumulated depreciation, depletion, amortization and impairment are as follows:
| As of December 31, | ||||||||||||||
| 2021 | 2020 | |||||||||||||
| Oil and natural gas properties: | (In thousands) | |||||||||||||
| Evaluated properties | $9,238,823 | $7,894,513 | ||||||||||||
| Unevaluated properties | 1,812,827 | 1,733,250 | ||||||||||||
| Total oil and natural gas properties | 11,051,650 | 9,627,763 | ||||||||||||
| Accumulated depreciation, depletion, amortization and impairment | (5,886,002) | (5,538,803) | ||||||||||||
| Total oil and natural gas properties capitalized | $5,165,648 | $4,088,960 | ||||||||||||
Costs Incurred
Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Acquisition costs: | (In thousands) | |||||||||||||||||||
| Evaluated properties | $677,250 | $— | $49,572 | |||||||||||||||||
| Unevaluated properties | 301,404 | 30,696 | 107,347 | |||||||||||||||||
| Development costs | 396,181 | 379,900 | 189,259 | |||||||||||||||||
| Exploration costs | 137,989 | 122,865 | 309,013 | |||||||||||||||||
| Total costs incurred | $1,512,824 | $533,461 | $655,191 | |||||||||||||||||
Standardized Measure
The following tables present the standardized measure of future net cash flows related to estimated proved oil and natural gas reserves together with changes therein, including a reduction for estimated plugging and abandonment costs that are also reflected as a liability on the balance sheet at December 31, 2021. You should not assume that the future net cash flows or the discounted future net cash flows, referred to in the tables below, represent the fair value of our estimated oil and natural gas reserves. Proved reserve estimates and future cash flows are based on the average realized prices for sales of oil, natural gas, and NGLs on the first calendar day of each month during the year. The following average realized prices were used in the calculation of proved reserves and the standardized measure of discounted future net cash flows.
| Years Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| Oil ($/Bbl) | $65.44 | $37.44 | $53.90 | |||||||||||||||||
| Natural gas ($/Mcf) | $3.31 | $1.02 | $1.55 | |||||||||||||||||
| NGLs ($/Bbl) | $29.19 | $11.10 | $15.58 | |||||||||||||||||
97
Future production and development costs are based on current costs with no escalations. Estimated future cash flows net of future income taxes have been discounted to their present values based on a 10% annual discount rate.
| Standardized Measure | ||||||||||||||||||||
| For the Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Future cash inflows | $23,775,358 | $12,458,033 | $20,891,469 | |||||||||||||||||
| Future costs | ||||||||||||||||||||
| Production | (8,038,362) | (5,433,496) | (6,717,088) | |||||||||||||||||
| Development and net abandonment | (1,927,789) | (2,204,301) | (3,058,861) | |||||||||||||||||
| Future net inflows before income taxes | 13,809,207 | 4,820,236 | 11,115,520 | |||||||||||||||||
| Future income taxes | (1,481,005) | (65,405) | (941,768) | |||||||||||||||||
| Future net cash flows | 12,328,202 | 4,754,831 | 10,173,752 | |||||||||||||||||
| 10% discount factor | (6,077,447) | (2,444,441) | (5,222,726) | |||||||||||||||||
| Standardized measure of discounted future net cash flows | $6,250,755 | $2,310,390 | $4,951,026 | |||||||||||||||||
| Changes in Standardized Measure | ||||||||||||||||||||
| For the Year Ended December 31, | ||||||||||||||||||||
| 2021 | 2020 | 2019 | ||||||||||||||||||
| (In thousands) | ||||||||||||||||||||
| Standardized measure at the beginning of the period | $2,310,390 | $4,951,026 | $2,941,293 | |||||||||||||||||
| Sales and transfers, net of production costs | (1,466,413) | (649,781) | (579,744) | |||||||||||||||||
| Net change in sales and transfer prices, net of production costs | 4,336,078 | (2,719,579) | (387,970) | |||||||||||||||||
| Net change due to purchases of in place reserves | 797,327 | — | 2,975,296 | |||||||||||||||||
| Net change due to sales of in place reserves | (105,376) | (202,928) | (303,526) | |||||||||||||||||
| Extensions, discoveries, and improved recovery, net of future production and development costs incurred | 583,976 | 250,759 | 607,146 | |||||||||||||||||
| Changes in future development cost | (81,480) | 361,008 | 205,398 | |||||||||||||||||
| Previously estimated development costs incurred | 209,078 | 318,470 | 134,037 | |||||||||||||||||
| Revisions of quantity estimates | (104,572) | (671,800) | (420,488) | |||||||||||||||||
| Accretion of discount | 234,495 | 536,958 | 314,921 | |||||||||||||||||
| Net change in income taxes | (765,956) | 383,999 | (210,641) | |||||||||||||||||
| Changes in production rates, timing and other | 303,208 | (247,742) | (324,696) | |||||||||||||||||
| Aggregate change | 3,940,365 | (2,640,636) | 2,009,733 | |||||||||||||||||
| Standardized measure at the end of period | $6,250,755 | $2,310,390 | $4,951,026 | |||||||||||||||||
ITEM 9. Changes In and Disagreementswith Accountants on Accounting and Financial Disclosure
None.
Disclosure controlsControls and procedures. Procedures. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed by an issuer in the reports that it files or submits under the Securities Exchange Act of 1934, as amended (the “Exchange Act”), is accumulated and communicated to the issuer’s management, including its principal executive and financial officers, or persons performing similar functions, as appropriate to allow timely decisions regarding required disclosure. Our Chief Executive Officer (“CEO”) and Chief Financial Officer (“CFO”) performed an evaluation of our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act). Based on this evaluation, our principal executive and principal financial officers have concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2017.2021.
Management’s Report on Internal Control Over Financial Reporting. Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Exchange Act Rules 13a-15(f) and 15d-15(f). Our internal control structure is designed to provide reasonable assurance to our management and Board of Directors regarding the reliability of financial reporting and the preparation and fair presentation of our financial statements prepared for external purposes in accordance with U.S. generally accepted accounting principles.GAAP. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an
98
evaluation of the effectiveness of our internal control over financial reporting as of December 31, 20172021 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework)(the (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2017.
2021.
Because of its inherent limitations, internal control over financial reporting can provide only reasonable assurance that the objectives of the control system are met and may not prevent or detect misstatements. In addition, any evaluation of the effectiveness of internal controls over financial reporting in future periods is subject to risk that those internal controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
The Company’s independent registered public accounting firm, Grant Thornton, LLP, has issued an attestation report regarding its assessment of the Company’s internal control over financial reporting as of December 31, 2017, which follows Part II, Item 9B of this filing. Additionally, the financial statements for the years ended December 31, 2017 and 2016, covered in this Annual Report on Form 10-K, have been audited by an independent registered public accounting firm, Grant Thornton LLP, whose report is2021, presented immediately preceding the Company’s financial statements included in Part II, Item 8 of this Annual Report on Form 10-K. The financial statements for the year ended December 31, 2015 were audited by the independent registered public accounting firm, Ernst & Young LLP, whose report is presented immediately preceding the company’s financial statements included in Part II, Item 8 of this2021 Annual Report on Form 10-K.
ITEM 9B.Other Information
None.
Not applicable.
PART III.
ITEM 10. Directors, Executive Officers and Corporate Governance
SEC not later than 120 days subsequent to December 31, 2021.
The Company has adopted a code of ethics that applies to the Company’s chief executive officer, chiefofficers, directors, employees, agents and representatives and includes a code of ethics for senior financial officerofficers that applies to the Chief Executive Officer, Chief Financial Officer and chief accounting officer.Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, andwww.callon.com.
ITEM 11. Executive Compensation
The information required by this item is available free of charge in print to any shareholder who requests it. Request for copies should be addressedincorporated herein by reference to the Secretary at mailing address Post Office Box 1287, Natchez, Mississippi 39121.
ITEM 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
ITEM 13. Certain Relationships and Related Transactions and Director Independence
ITEM 14. Principal Accountant Fees and Services
PART IV.
(a) Documents filed as part of this 2021 Annual Report on Form 10-K:
See index to Financial Statements and Supplementary Data on page 56.
(2) Financial Statement Schedules
All schedules have been omitted because they are either not applicable, not required or the information called for therein appears in the consolidated financial statements and financial statement schedules that are filed in Part II, Item 8 ofor notes thereto.
(3) Exhibits
| Incorporated by reference (File No. 001-14039, unless otherwise indicated) | |||||||||||||||||||||||||||||
| Exhibit Number | Description | Form | Exhibit | Filing Date | |||||||||||||||||||||||||
| 2.1 | (d) | 8-K | 2.1 | 06/13/2019 | |||||||||||||||||||||||||
| 2.2 | (d) | 8-K | 2.1 | 07/15/2019 | |||||||||||||||||||||||||
| 2.3 | 10-Q | 2.2 | 11/05/2019 | ||||||||||||||||||||||||||
| 2.4 | 8-K | 2.1 | 11/14/2019 | ||||||||||||||||||||||||||
| 3.1 | 10-Q | 3.1 | 11/03/2016 | ||||||||||||||||||||||||||
| 3.2 | 8-K | 3.1 | 12/20/2019 | ||||||||||||||||||||||||||
| 3.3 | 8-K | 3.1 | 08/07/2020 | ||||||||||||||||||||||||||
| 3.4 | 8-K | 3.1 | 05/14/2021 | ||||||||||||||||||||||||||
| 3.5 | 10-K | 3.2 | 02/27/2019 | ||||||||||||||||||||||||||
| 4.1 | 10-K | 4.1 | 02/28/2018 | ||||||||||||||||||||||||||
| 4.2 | 10-K | 4.2 | 02/25/2021 | ||||||||||||||||||||||||||
| 4.3 | 8-K | 4.1 | 10/04/2016 | ||||||||||||||||||||||||||
| 4.4 | 8-K | 4.3 | 12/20/2019 | ||||||||||||||||||||||||||
| 4.5 | 8-K | 4.2 | 10/04/2016 | ||||||||||||||||||||||||||
| 4.6 | 8-K | 4.1 | 05/24/2017 | ||||||||||||||||||||||||||
| 4.7 | 8-K | 4.1 | 06/07/2018 | ||||||||||||||||||||||||||
| 4.8 | 8-K | 4.4 | 12/20/2019 | ||||||||||||||||||||||||||
| 4.9 | 8-K | 4.2 | 06/07/2018 | ||||||||||||||||||||||||||
| 4.10 | 8-K(File No. 000-29187-87) | 4.1 | 05/28/2008 | ||||||||||||||||||||||||||
| 4.11 | 8-K(File No. 000-29187-87) | 4.2 | 05/22/2015 | ||||||||||||||||||||||||||
| 4.12 | 8-K(File No. 000-29187-87) | 4.2 | 07/14/2017 | ||||||||||||||||||||||||||
| 4.13 | 8-K | 4.1 | 12/20/2019 | ||||||||||||||||||||||||||
| 4.14 | 8-K | 4.2 | 12/20/2019 | ||||||||||||||||||||||||||
100
| 4.15 | 8-K | 4.5 | 12/20/2019 | ||||||||||||||||||||||||||
| 4.16 | 8-K | 4.1 | 07/07/2021 | ||||||||||||||||||||||||||
| 4.17 | (a) | ||||||||||||||||||||||||||||
| 4.18 | (a) | ||||||||||||||||||||||||||||
| 4.19 | 8-K | 4.1 | 11/08/2021 | ||||||||||||||||||||||||||
| 10.1 | (d) | 8-K | 10.1 | 12/20/2019 | |||||||||||||||||||||||||
| 10.2 | (d) | 10-Q | 10.1 | 05/11/2020 | |||||||||||||||||||||||||
| 10.3 | 8-K | 10.2 | 10/01/2020 | ||||||||||||||||||||||||||
| 10.4 | 8-K | 10.3 | 10/01/2020 | ||||||||||||||||||||||||||
| 10.5 | 10-Q | 10.6 | 05/06/2021 | ||||||||||||||||||||||||||
| 10.6 | 10-Q | 10.3 | 11/04/2021 | ||||||||||||||||||||||||||
| 10.7 | (b) | 10-K | 10.11 | 02/28/2018 | |||||||||||||||||||||||||
| 10.8 | (b) | DEF 14A | A | 03/23/2018 | |||||||||||||||||||||||||
| 10.9 | (b) | 10-K | 10.7 | 02/27/2020 | |||||||||||||||||||||||||
| 10.10 | (b) | 10-K | 10.23 | 02/27/2019 | |||||||||||||||||||||||||
| 10.11 | (b) | 10-K | 10.23 | 02/27/2020 | |||||||||||||||||||||||||
| 10.12 | (b) | 10-K | 10.24 | 02/27/2020 | |||||||||||||||||||||||||
| 10.13 | (b) | 10-K | 10.25 | 02/27/2020 | |||||||||||||||||||||||||
| 10.14 | (b) | DEF 14A | B | 04/28/2020 | |||||||||||||||||||||||||
| 10.15 | (b) | 8-K | 10.5 | 04/16/2021 | |||||||||||||||||||||||||
| 10.16 | (b) | 10-Q | 10.3 | 08/05/2020 | |||||||||||||||||||||||||
| 10.17 | (b) | 10-Q | 10.4 | 08/05/2020 | |||||||||||||||||||||||||
| 10.18 | (b) | 10-Q | 10.4 | 11/03/2020 | |||||||||||||||||||||||||
| 10.19 | (b) | 10-Q | 10.5 | 11/03/2020 | |||||||||||||||||||||||||
| 10.20 | (b) | 10-K | 10.29 | 02/25/2021 | |||||||||||||||||||||||||
| 10.21 | (b) | 8-K | 10.1 | 04/16/2021 | |||||||||||||||||||||||||
| 10.22 | (b) | 8-K | 10.2 | 04/16/2021 | |||||||||||||||||||||||||
| 10.23 | (b) | 8-K | 10.3 | 04/16/2021 | |||||||||||||||||||||||||
| 10.24 | (b) | 8-K | 10.4 | 04/16/2021 | |||||||||||||||||||||||||
| 10.25 | (b) | 10-Q | 10.1 | 11/04/2021 | |||||||||||||||||||||||||
| 10.26 | (b) | 10-Q | 10.2 | 11/04/2021 | |||||||||||||||||||||||||
101
| 10.27 | 8-K | 10.1 | 06/22/2021 | ||||||||||||||||||||||||||
| 10.28 | 8-K | 10.1 | 08/05/2021 | ||||||||||||||||||||||||||
| 10.29 | 8-K | 10.2 | 08/05/2021 | ||||||||||||||||||||||||||
| 10.30 | 8-K | 10.1 | 08/05/2021 | ||||||||||||||||||||||||||
| 10.31 | 8-K | 10.2 | 08/05/2021 | ||||||||||||||||||||||||||
| 21.1 | (a) | ||||||||||||||||||||||||||||
| 22.1 | (a) | ||||||||||||||||||||||||||||
| 23.1 | (a) | ||||||||||||||||||||||||||||
| 23.2 | (a) | ||||||||||||||||||||||||||||
| 31.1 | (a) | ||||||||||||||||||||||||||||
| 31.2 | (a) | ||||||||||||||||||||||||||||
| 32.1 | (c) | ||||||||||||||||||||||||||||
| 99.1 | (a) | ||||||||||||||||||||||||||||
| 101.INS | (a) | XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||||||||||||||||||||||
| 101.SCH | (a) | Inline XBRL Taxonomy Extension Schema Document | |||||||||||||||||||||||||||
| 101.CAL | (a) | Inline XBRL Taxonomy Extension Calculation Linkbase Document. | |||||||||||||||||||||||||||
| 101.DEF | (a) | Inline XBRL Taxonomy Extension Definition Linkbase Document. | |||||||||||||||||||||||||||
| 101.LAB | (a) | Inline XBRL Taxonomy Extension Label Linkbase Document. | |||||||||||||||||||||||||||
| 101.PRE | (a) | Inline XBRL Taxonomy Extension Presentation Linkbase Document. | |||||||||||||||||||||||||||
| 104 | (a) | Cover Page Interactive Data File - the cover page interactive data file does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document. | |||||||||||||||||||||||||||
(a)Filed herewith.
(b)Indicates management compensatory plan, contract, or arrangement.
(c)Furnished herewith. Pursuant to SEC Release No. 33-8212, this certification will be treated as “accompanying” this report on Form 10-K.and not “filed” as part of such report for purposes of Section 18 of the Exchange Act or otherwise subject to the liability of Section 18 of the Exchange Act, and this certification will not be deemed to be incorporated by reference into any filing under the Securities Act of 1933, except to the extent that the registrant specifically incorporates it by reference.
None.
102
SIGNATURES
| Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized. | |||||||||||||||||||||||
| Callon Petroleum Company | |||||||||||||||||||||||
| /s/ | Date: | February | |||||||||||||||||||||
| By: | |||||||||||||||||||||||
| Chief Financial Officer (principal financial officer) | |||||||||||||||||||||||
| Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated. | |||||||||||||||||||||||
| /s/ Joseph C. Gatto, Jr. | Date: | February | |||||||||||||||||||||
| Joseph C. Gatto, Jr. (principal executive officer) | |||||||||||||||||||||||
| /s/ Kevin Haggard | Date: | February 24, 2022 | |||||||||||||||||||||
| /s/ Gregory F. Conaway | Date: | February 24, 2022 | |||||||||||||||||||||
| /s/ L. Richard Flury | Date: | February | |||||||||||||||||||||
| L. Richard Flury | |||||||||||||||||||||||
| /s/ Frances Aldrich Sevilla-Sacasa | Date: | February 24, 2022 | |||||||||||||||||||||
| /s/ Matthew R. Bob | Date: | February 24, 2022 | |||||||||||||||||||||
| Matthew R. Bob (director) | |||||||||||||||||||||||
| /s/ Barbara J. Faulkenberry | Date: | February 24, 2022 | |||||||||||||||||||||
| Barbara J. Faulkenberry (director) | |||||||||||||||||||||||
| /s/ Michael L. Finch | Date: | February 24, 2022 | |||||||||||||||||||||
| Michael L. Finch (director) | |||||||||||||||||||||||
| /s/ Larry D. McVay | Date: | February 24, 2022 | |||||||||||||||||||||
| Larry D. McVay (director) | |||||||||||||||||||||||
| /s/ Anthony J. Nocchiero | Date: | February | |||||||||||||||||||||
| Anthony J. Nocchiero (director) | |||||||||||||||||||||||
| /s/ Mary Shafer-Malicki | Date: | February 24, 2022 | |||||||||||||||||||||
| /s/ James M. Trimble | Date: | February | |||||||||||||||||||||
| James M. Trimble (director) | |||||||||||||||||||||||
| /s/ Steven A. Webster | Date: | February 24, 2022 | |||||||||||||||||||||
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