10-K

UNITED STATES 

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 FORM 10-K

☒ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the fiscal year ended December 31, 2019

or

☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from ____________ to ____________

Commission File Number 001-14039

Callon Petroleum Company

(Exact Name of Registrant as Specified in Its Charter)

_______________________________________________

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Delaware		64-0844345
State or Other Jurisdiction of Incorporation or Organization		I.R.S. Employer Identification No.
One Briarlake Plaza
2000 W. Sam Houston Parkway S., Suite 2000
Houston,	Texas	77042
Address of Principal Executive Offices		Zip Code

281-589-5200

(Registrant’s Telephone Number, Including Area Code)

Title of Each Class	Securities registered pursuant to Section 12(b) of the Act:	Name of Each Exchange on Which Registered
Common Stock, $0.01 par value	CPE	New York Stock Exchange
	Securities registered pursuant to section 12 (g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.      Yes  ☒     No  ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act.      Yes  ☐     No  ☒

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.      Yes  ☒     No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).      Yes  ☒     No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act:

Large accelerated filer	☒	Accelerated filer	☐	Non-accelerated filer	☐
Smaller reporting company	☐	Emerging growth company	☐

.

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.   ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).      Yes  ☐     No  ☒

The aggregate market value of the voting and non-voting common equity held by non-affiliates of the registrant as of June 30, 2019 was approximately $1.5 billion.

The Registrant had 396,684,449 shares of common stock outstanding as of February 21, 2020.  

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2019) relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which are incorporated into Part III of this Form 10-K.

TABLE OF CONTENTS

Special Note Regarding Forward Looking Statements		3
Glossary of Certain Terms		5
Part I
Items 1 and 2.	Business and Properties	7
	Oil and Natural Gas Properties	9
	Proved Oil and Gas Reserves	10
	Capital Budget	13
	Drilling Activity	13
	Productive Wells	14
	Production Volumes, Average Sales Prices and Operating Costs	15
	Major Customers	16
	Leasehold Acreage	16
	Other	16
	Regulations	18
	Commitments and Contingencies	26
	Available Information	26
Item 1A.	Risk Factors	27
Item 1B.	Unresolved Staff Comments	39
Item 3.	Legal Proceedings	39
Item 4.	Mine Safety Disclosures	39
Part II
Item 5.	Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities	40
	Performance Graph	41
Item 6.	Selected Financial Data	42
Item 7.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
	General	43
	Overview	43
	Results of Operations	44
	Liquidity and Capital Resources	48
	Summary of Critical Accounting Policies	53
Item 7A.	Quantitative and Qualitative Disclosures About Market Risk	56
Item 8.	Financial Statements and Supplementary Data	58
	Reports of Independent Registered Public Accounting Firm	59
	Consolidated Balance Sheets	63
	Consolidated Statements of Operations	64
	Consolidated Statements of Stockholders’ Equity	65
	Consolidated Statements of Cash Flows	66
	Notes to Consolidated Financial Statements	67
	Supplemental Information on Oil and Natural Gas Operations (Unaudited)	97
	Supplemental Quarterly Financial Information (Unaudited)	102
Item 9.	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure	103
Item 9A.	Controls and Procedures	103
Item 9B.	Other Information	103
Part III
Item 10.	Directors, Executive Officers and Corporate Governance	104
Item 11.	Executive Compensation	104
Item 12.	Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters	104
Item 13.	Certain Relationships and Related Transactions and Director Independence	104
Item 14.	Principal Accountant Fees and Services	104
Part IV.
Item 15.	Exhibits	105
Item 16.	Form 10-K Summary	108
Signatures		109

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Special Note Regarding Forward Looking Statements

This report includes “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933 (the “Securities Act”), as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These statements involve known and unknown risks, uncertainties and other factors that may cause our actual results, performance or achievements to be materially different from any future results, performance or achievements expressed or implied by the forward-looking statements. In some cases, you can identify forward-looking statements in this Form 10-K by words such as “anticipate,” “project,” “intend,” “estimate,” “expect,” “believe,” “predict,” “budget,” “projection,” “goal,” “plan,” “forecast,” “target” or similar expressions.

All statements, other than statements of historical facts, included in this report that address activities, events or developments that we expect or anticipate will or may occur in the future are forward-looking statements, including such things as:

• matters relating to the acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”);

• our oil and natural gas reserve quantities, and the discounted present value of these reserves;

• the amount and nature of our capital expenditures;

• our future drilling and development plans and our potential drilling locations;

• the timing and amount of future capital and operating costs;

• production decline rates from our wells being greater than expected;

• commodity price risk management activities and the impact on our average realized prices;

• business strategies and plans of management;

• our ability to consummate and efficiently integrate recent acquisitions; and

• prospect development and property acquisitions.

We caution you that the forward-looking statements contained in this Annual Report on Form 10-K (this “2019 Annual Report on Form 10-K”) are subject to all of the risks and uncertainties, many of which are beyond our control, incident to the exploration for and development, production and sale of oil and natural gas. We disclose these and other important factors that could cause our actual results to differ materially from our expectations under “Risk Factors” in Item 1A of Part I in this 2019 Annual Report on Form 10-K. These factors include:

• general economic conditions including the availability of credit and access to existing lines of credit;

• the volatility of oil and natural gas prices;

• the uncertainty of estimates of oil and natural gas reserves;

• impairments;

• the impact of competition;

• the availability and cost of seismic, drilling and other equipment, waste and water disposal infrastructure, and personnel;

• operating hazards inherent in the exploration for and production of oil and natural gas;

• difficulties encountered during the exploration for and production of oil and natural gas;

• the potential impact of future drilling on production from existing wells

• difficulties encountered in delivering oil and natural gas to commercial markets;

• changes in customer demand and producers’ supply;

• the uncertainty of our ability to attract capital and obtain financing on favorable terms;

• compliance with, or the effect of changes in, the extensive governmental regulations regarding the oil and natural gas business including those related to climate change and greenhouse gases;

• the impact of government regulation, including regulation of hydraulic fracturing and water disposal wells;

• any increase in severance or similar taxes;

• the financial impact of accounting regulations and critical accounting policies;

• the comparative cost of alternative fuels;

• credit risk relating to the risk of loss as a result of non-performance by our counterparties;

• cyberattacks on the Company or on systems and infrastructure used by the oil and natural gas industry;

• weather conditions;

• risks associated with acquisitions, including the acquisition of Carrizo (the “Carrizo Acquisition” or the “Merger”);

• failure to realize the expected benefits of the Carrizo Acquisition;

• any litigation relating to the Carrizo Acquisition; and

• any other factors listed in the reports we have filed and may file with the SEC.

Should one or more of these risks or uncertainties occur, or should underlying assumptions prove incorrect, our actual results and plans could differ materially from those expressed in any forward-looking statements. Additional risks or uncertainties that are not currently known to us, that we currently deem to be immaterial, or that could apply to any company could also materially adversely affect our business, financial condition, or future results. Any forward-looking statement speaks only as of the date of which such statement is made and the Company undertakes no obligation to correct or update any forward-looking statement, whether as a result of new information, future events or otherwise, except required by applicable law.

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In addition, we caution that reserve engineering is a process of estimating oil and natural gas accumulated underground and cannot be measured exactly. Accuracy of reserve estimates depend on a number of factors including data available at the point in time, engineering interpretation of the data, and assumptions used by the reserve engineers as it relates to price and cost estimates and recoverability. New results of drilling, testing, and production history may result in revisions of previous estimates and, if significant, would impact future development plans. As such, reserve estimates may differ from actual results of oil and natural gas quantities ultimately recovered.

Except as required by applicable law, all forward-looking statements attributable to us are expressly qualified in their entirety by this cautionary statement. This cautionary statement should also be considered in connection with any subsequent written or oral forward-looking statements that we or persons acting on our behalf may issue.

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GLOSSARY OF CERTAIN TERMS

All defined terms under Rule 4-10(a) of Regulation S-X shall have their prescribed meanings when used in this report. As used in this document:

• ARO:  asset retirement obligation.

• ASU: accounting standards update.

• Bbl or Bbls:  barrel or barrels of oil or natural gas liquids.

• Boe:  barrel of oil equivalent, determined by using the ratio of one Bbl of oil or NGLs to six Mcf of natural gas.  The ratio of one barrel of oil or NGLs to six Mcf of natural gas is commonly used in the industry and represents the approximate energy equivalence of oil or NGLs to natural gas, and does not represent the economic equivalency of oil and NGLs to natural gas. The sales price of a barrel of oil or NGLs is considerably higher than the sales price of six Mcf of natural gas.

• Boe/d:  Boe per day.

• BLM: Bureau of Land Management.

• Btu:  a British thermal unit, which is a measure of the amount of energy required to raise the temperature of one pound of water one degree Fahrenheit.

• Completion: the process of treating a drilled well followed by the installation of permanent equipment for the production of oil or natural gas or, in the case of a dry hole, the reporting of abandonment to the appropriate agency.

• Cushing: an oil delivery point that serves as the benchmark oil price for West Texas Intermediate.

• Development well: A well drilled within the proved area of an oil or natural gas reservoir to the depth of a stratigraphic horizon known to be productive.

• EPA: United States Environmental Protection Agency.

• Exploratory well: A well drilled to find a new field or to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir.

• FASB: Financial Accounting Standards Board.

• GAAP: Generally Accepted Accounting Principles in the United States.

• GHG: greenhouse gases.

• Henry Hub: a natural gas pipeline delivery point that serves as the benchmark natural gas price underlying NYMEX natural gas futures contracts.

• Horizontal drilling: a drilling technique used in certain formations where a well is drilled vertically to a certain depth and then drilled at an angle within a specified interval.

• ICE: Intercontinental Exchange.

• LIBOR:  London Interbank Offered Rate.

• LOE:  lease operating expense.

• MBbls:  thousand barrels of oil.

• MBoe:  thousand Boe.

• Mcf:  thousand cubic feet of natural gas.

• MEH: Magellan East Houston, a delivery point in Houston, Texas that serves as a benchmark for crude oil.

• MMBoe:  million Boe.

• MMBtu:  million Btu.

• MMcf:  million cubic feet of natural gas.

• NGL or NGLs:  natural gas liquids, such as ethane, propane, butanes and natural gasoline that are extracted from natural gas production streams.

• Non-productive well: A well that is found to be incapable of producing oil or gas in sufficient quantities to justify completion, or upon completion, the economic operation of an oil or gas well.

• NYMEX:  New York Mercantile Exchange.

• Oil: includes crude oil and condensate.

• OPEC: Organization of Petroleum Exporting Countries.

• PDPs:  proved developed producing reserves.

• Productive well: A well that is found to be capable of producing oil or gas in sufficient quantities to justify completion as an oil or gas well.

• Proved developed producing reserves: Proved reserves that can be expected to be recovered through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well.

• Proved reserves: Those reserves which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced, or the operator must be reasonably certain that it will commence the project, within a reasonable time.

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The area of the reservoir considered as proved includes all of the following:

a.The area identified by drilling and limited by fluid contacts, if any, and

b. Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

Reserves that can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when both of the following occur:

a. Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based, and

b.The project has been approved for development by all necessary parties and entities, including governmental entities.

Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period before the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

• Proved undeveloped reserves: Proved reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless specific circumstances justify a longer time. Under no circumstances shall estimates of proved undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, or by other evidence using reliable technology establishing reasonable certainty.

• PUDs:  proved undeveloped reserves.

• PV-10 (Non-GAAP): the present value of estimated future gross revenue to be generated from the production of estimated net proved reserves, net of estimated production and future development costs, using prices and costs in effect as of the date indicated (unless such prices or costs are subject to change pursuant to contractual provisions), without giving effect to non-property related expenses such as general and administrative expenses, debt service and future income tax expenses or to depreciation, depletion and amortization, discounted using an annual discount rate of 10 percent. While this measure does not include the effect of income taxes as it would in the use of the standardized measure of discounted future net cash flows calculation, it does provide an indicative representation of the relative value of the Company on a comparative basis to other companies from period to period. This is a non-GAAP measure. See “Items 1 and 2 - Business and Properties - Proved Oil and Gas Reserves - Reconciliation of Standardized Measure of Discounted Future Net Cash Flows (GAAP) to PV-10 (Non-GAAP)”.

• Realized price: the cash market price less all expected quality, transportation and demand adjustments.

• Royalty interest: an interest that gives an owner the right to receive a portion of the resources or revenues without having to carry any costs of development.

• RSU: restricted stock units.

• SEC:  United States Securities and Exchange Commission.

• Waha: a natural gas delivery point in West Texas that serves as the benchmark for natural gas.

• Working interest: an operating interest that gives the owner the right to drill, produce and conduct operating activities on the property and receive a share of production and requires the owner to pay a share of the costs of drilling and production operations.

• WTI: West Texas Intermediate grade crude oil, used as a pricing benchmark for sales contracts and NYMEX oil futures contracts.

With respect to information relating to our working interest in wells or acreage, “net” oil and gas wells or acreage is determined by multiplying gross wells or acreage by our working interest therein. Unless otherwise specified, all references to wells and acres are gross. 

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PART I.

ITEMS 1 and 2 – Business and Properties

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 were incorporated in the state of Delaware in 1994.

We are an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. 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. In 2019, though our acquisition of Carrizo, we double our core acreage position in the Delaware Basin and entered the Eagle Ford Shale. Our primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generating business in the Eagle Ford Shale.

Major Developments in 2019

Merger with Carrizo Oil & Gas, Inc. On December 20, 2019, we completed our acquisition of Carrizo, in an all-stock transaction. The addition of Carrizo’s assets increased our portfolio to: (i) over 116,000 net acres in the Permian Basin, which doubled our footprint in the Southern Delaware Basin and (ii) expanded our portfolio to include over 76,000 net acres in the mature, high-margin, free cash flow generating Eagle Ford Shale.

Ranger Divestiture. On June 12, 2019, we completed our 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 to be paid to us of up to $60.0 million based on West Texas Intermediate average annual pricing over a three-year period. The divestiture encompassed the Ranger operating area in the southern Midland Basin which included approximately 9,850 net Wolfcamp acres with an average 66% working interest.

See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion.

Financing and Liquidity Activity. In connection with the Carrizo Acquisition, we entered into a credit agreement with a syndicate of lenders (the “Credit Facility”), which has a maximum credit amount of $5.0 billion. As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion. During 2019, we also redeemed the remaining outstanding 10% Series A Cumulative Preferred Stock (“Preferred Stock”) for a total redemption price of $73.0 million.

See “Note 7 – Borrowings” and “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for further discussion.

Operational Activity. Our drilling activity during 2019 was predominantly associated with the horizontal development of several prospective intervals in the Permian Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, as well as the Eagle Ford Shale, which we entered into in late 2019 as a result of the Carrizo Acquisition. As a result of our horizontal development efforts and contributions from acquisitions, our net daily production for the year ended December 31, 2019 as compared to the prior year grew approximately 26% to 41,331 Boe/d (approximately 77% oil). For the year ended December 31, 2019, our estimated proved reserves were 540.0 MMBoe, an increase of 126% as compared to the year ended December 31, 2018 primarily as a result of the merger with Carrizo described above, and included proved oil reserves of 346.4 MMBbls (64% of total proved reserves). Approximately 43% of our 2019 year-end estimated proved reserves were classified as proved developed.

We intend to grow our reserves and production through the drilling and development of our multi-year inventory of identified drilling locations. We will also seek to grow our inventory of locations through delineation of emerging zones and selective “bolt-on” acquisition and leasing programs in areas complementary to our core operating areas.

Our Business Strategy

Our principal objective is to enhance shareholder value through capital efficient growth in proved reserves and associated production and cash flows while acting as a responsible corporate citizen in the areas 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 of development that are educated by extensive analysis of subsurface data and empirical well results;

• Maintaining strong cash margins per unit of production through cost management and proactive investment in production infrastructure;

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• Improving the capital efficiency of our operations in terms of both well productivity and capital outlays, including supporting facilities;

• Maturing our asset base into a sustainable operating model for profitable reinvestment of cash flows for attractive, long-term returns on capital;

• Growing our inventory of well locations through delineation of emerging targets on our existing acreage positions and selective acquisitions of leasehold rights and mineral interests in areas complementary to our existing core operating areas; and

• Preserving a strong financial position, focusing on appropriate capital allocation decisions under various commodity pricing scenarios, prudent risk management and generating free cash flow to reduce leverage.

Our Strengths

We believe the following attributes position Callon to achieve its objectives:

• Strong Foundation - Reputation as a safe and responsible operator built over several decades in the oil and gas industry;

• Quality Assets - High quality Permian Basin asset base with several years of proven well results from multiple target zones that benefit from early investments in critical supporting infrastructure including sustainable investments in water recycling and a more mature asset base in the Eagle Ford Shale which has lower operational risk and generates predictable, repeatable well results;

• Operational Control - High degree of operational control that allows us to efficiently maximize value through long-term and daily decisions that drive our strategy;

• Talented Workforce - Seasoned employee base that has continued to benefit from the hiring of quality employees across various disciplines, as well as the integration of employees from the Carrizo Acquisition, that have been integrated into our unifying culture.

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Oil and Natural Gas Properties

Summary of 2019 Proved Reserves, Production and Drilling by Region

	Permian Basin			Eagle Ford Shale			Total
Proved reserves (1)
Crude oil (MBbls)		237,413			108,948			346,361
Natural gas (MMcf)		656,594			100,540			757,134
NGLs (MBbls)		50,128			17,334			67,462
Total proved reserves (MBoe)		396,973			143,039			540,012
Proved reserves by classification (MBoe)
Proved developed		164,503			66,474			230,977
Proved undeveloped		232,470			76,565			309,035
Total proved reserves (MBoe)		396,973			143,039			540,012
Percent of proved developed reserves		71	%		29	%		100	%
Percent of proved undeveloped reserves		75	%		25	%		100	%
Percent of total reserves		74	%		26	%		100	%
Production volumes (1)(2)	Total	Per Day (2)		Total	Per Day (2)		Total	Per Day (2)
Crude oil (MBbls and Bbls/d)	11,365	31,136		300	821		11,665	31,957
Natural gas (MMcf and Mcf/d)	19,484	53,381		234	640		19,718	54,021
NGLs (MBbls and Bbls/d)	93	254		42	116		135	370
Total production volumes (MBoe and Boe/d)	14,705	40,287		381	1,044		15,086	41,331
Percent of total production		97	%		3	%		100	%
	Permian Basin			Eagle Ford Shale			Total
Operated Well Data	Gross	Net		Gross	Net		Gross	Net
Year Ended December 31, 2019
Drilled (2)	61	53.7		2	2.0		63	55.7
Completed (2)	55	47.1		—	—		55	47.1
December 31, 2019
Drilled but uncompleted	28	25.0		36	32.7		64	57.7
Producing	810	702.6		599	539.7		1,409	1,242.3

(1) The estimated proved reserves acquired in the Carrizo Acquisition and production associated with such reserves are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve and production volumes are on a two-stream basis.

(2) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

Regional Overview

Permian Basin

As of December 31, 2019, we owned 173,922 gross (116,784 net) acres in the Permian Basin, all of which was located in the Midland and Delaware Basins. Average net production from our Permian Basin properties increased approximately 22% to 40,287 Boe/d in 2019 from 32,926 Boe/d in 2018. In the fourth quarter of 2019, we closed on the Carrizo Acquisition which added approximately 45,000 net acres in the Delaware Basin to our portfolio. We currently expect to direct the majority of our 2020 Capital Budget, as defined below, towards opportunities in the Permian Basin.

Eagle Ford Shale

We acquired our Eagle Ford properties, primarily located in LaSalle County and, to a lesser extent, in McMullen, Frio and Atascosa counties in Texas, through the Carrizo Acquisition. As of December 31, 2019, we held interests in approximately 90,560 gross (76,234 net) acres.

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Proved Oil and Gas Reserves

The following table sets forth summary information with respect to our estimated proved reserves, standardized measure of discounted future net cash flows and PV-10 for the years ended December 31, 2019, 2018, and 2017. The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). For further information concerning D&M’s and Ryder Scott’s estimates of our proved reserves as of December 31, 2019, see the reserve reports included as exhibits to this 2019 Annual Report on Form 10-K. The prices used in the calculation of our estimated proved reserves and PV-10 were based on the average realized prices for sales of oil, natural gas liquids (“NGLs”), and natural gas on the first calendar day of each month during the year (“12-Month Average Realized Price”) in accordance with SEC rules.

	As of December 31,
	2019			2018			2017
Proved developed reserves (1)
Crude oil (MBbls)	152,687			92,202			51,920
Natural gas (MMcf)	320,676			218,417			104,389
NGLs (MBbls)	24,844			—			—
Total proved developed reserves (MBoe)	230,977			128,605			69,318
Proved undeveloped reserves (1)
Crude oil (MBbls)	193,674			87,895			55,152
Natural gas (MMcf)	436,458			132,049			75,021
NGLs (MBbls)	42,618			—			—
Total proved undeveloped reserves (MBoe)	309,035			109,903			67,656
Total proved reserves (1)
Crude oil (MBbls)	346,361			180,097			107,072
Natural gas (MMcf)	757,134			350,466			179,410
NGLs (MBbls)	67,462			—			—
Total proved reserves (MBoe)	540,012			238,508			136,974
Proved developed reserves %	43		%	54		%	51		%
Proved undeveloped reserves %	57		%	46		%	49		%
Average realized prices
Crude oil ($/Bbl)		$53.90			$58.40			$49.48
Natural gas ($/Mcf)		$1.55			$3.64			$3.47
NGLs ($/Bbl)		$15.58		—			—
Standardized measure of discounted future net cash flows (GAAP) (in millions)		$4,951.0			$2,941.3			$1,556.7
PV-10 (Non-GAAP):
Proved developed PV-10		$3,246.8			$2,222.0			$1,030.3
Proved undeveloped PV-10	2,122.8			927.2			546.4
Total PV-10 (Non-GAAP)		$5,369.6			$3,149.2			$1,576.8

(1) The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis.

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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. The definition of PV-10 as defined in “Glossary of Certain Terms” may differ significantly from the definitions used by other companies to compute similar measures. As a result, PV-10 as defined may not be comparable to similar measures provided by other companies. A reconciliation of the standardized measure of discounted future net cash flows to PV-10 is presented below. 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,
	2019		2018		2017
	(In millions)
Standardized measure of discounted future net cash flows (GAAP)		$4,951.0		$2,941.3		$1,556.7
Add: present value of future income taxes discounted at 10% per annum	418.6		207.9		20.1
PV-10 (Non-GAAP)		$5,369.6		$3,149.2		$1,576.8

Proved Reserves

As of December 31, 2019, our estimated proved reserves totaled 540.0 MMBoe, an increase of 126% from the prior year end, and included 346.4 MMBbls of oil, 757.1 Bcf of natural gas and 67.5 MMBbls of NGLs with a standardized measure of discounted future net cash flows of $5.0 billion ⁽¹⁾. Oil constituted approximately 64% of our total estimated proved reserves and approximately 66% of our total estimated proved developed reserves. We added 59.4 MMBoe of new reserves in extensions and discoveries through our development efforts in our operating areas, of which 17.1 MMBoe were proved developed at a cost of $226.3 million, where we drilled a total of 63 gross (55.7 net) wells. We purchased reserves in place of 326.8 MMBoe associated with the Carrizo Acquisition. Sales of reserves in place of 32.5 MMBoe primarily included 18.6 MMBoe of proved developed reserves and 8.5 MMBoe of PUD reserves associated with the Ranger Divestiture. See “Note 4 - Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for further discussion of the Carrizo Acquisition and the Ranger Divestiture.

Our net revisions of previous estimates were primarily related to revisions of proved undeveloped reserves. We reduced our estimated proved reserves through total net revisions of 37.2 MMBoe due to the following factors:

• 21.7 MMBoe from the observed impact of well spacing tests on producing wells and the related impact on PUD reserve estimates as we advance larger scale development concepts across our multi-zone inventory;

• 9.8 MMBoe from the reclassifications of PUDs within our optimized development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which afforded the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation; and

• 5.7 MMBoe from the adverse effect of pricing and other economic factors

The following table provides a summary of the changes in our proved reserves for the year ended December 31, 2019.

	Total (MBoe)
Proved reserves as of December 31, 2018	238,508
Extensions and discoveries	59,424
Revisions to previous estimates	(37,216	)
Purchase of reserves in place (1)	326,838
Sales of reserves in place	(32,456	)
Production	(15,086	)
Proved reserves as of December 31, 2019	540,012

(1) The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis.

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Proved Undeveloped Reserves

Annually, we review our PUDs to ensure appropriate plans exist for development of this reserve category. PUD reserves are recorded only if we have plans to convert these reserves into PDPs within five years of the date they are first recorded. Our development plans include the allocation of capital to projects included within our 2020 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 five year period.

The Company had extensions and discoveries of 42.4 MMBoe for our PUDs that were due to additional offset locations associated with our drilling program. During 2019, we acquired 201.5 MMBoe of PUD locations associated with the Carrizo Acquisition and had sales of reserves in place of 11.2 MMBoe of PUDs which was primarily a result of the Ranger Divestiture.

We had net revisions of 23.0 MMBoe to PUDs in 2019. These revisions reflect the impact of well spacing tests on certain PUD estimates and reclassifications of certain PUDs within our optimized development plans that were moved outside of the five-year development window as well as the adverse effect of pricing and other economic factors. The primary driver of the changes in our previous development plan was the Carrizo Acquisition which afforded the opportunity to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation.

During 2019, we converted 11.0 MMBoe of PUDs that were booked as PUDs as of December 31, 2018 to proved developed at a total cost of $103.9 million, or $9.45 per Boe. We converted an additional 2.5 MMBoe of PUDs that were booked as PUDs during 2019 to proved developed at a total cost of $28.6 million, or $11.44 per Boe. Although our PUD conversion was below 20% for 2019, we currently estimate that we will convert approximately 50% of our PUDs as of December 31, 2019 in 2020 and 2021.

During 2019, we also incurred $15.9 million on PUDs that were drilled but uncompleted as of December 31, 2019. As of December 31, 2019, we had 32.2 MMBoe of PUDs associated with drilled but uncompleted wells, of which 29.3 MMBoe were associated with the Carrizo Acquisition. All of the reserves associated with drilled but uncompleted wells are scheduled to be completed in 2020. We expect to incur approximately $203.0 million of capital expenditures to complete these wells.

At December 31, 2019, we did not have any reserves that have remained undeveloped for five or more years since the date of their initial booking and all PUD locations are scheduled to be developed within five years of their initial booking.

Qualifications of Technical Persons

In accordance with the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers, D&M prepared approximately 40% of our estimates of proved reserves as of December 31, 2019 and 100% of our proved reserves as of December 31, 2018 and 2017. Ryder Scott prepared the estimates of proved reserves associated with the Carrizo Acquisition, which comprised approximately 60% of our proved reserves as of December 31, 2019. The technical persons responsible for preparing the reserves estimates meet the requirements regarding qualifications, independence, objectivity and confidentiality set forth in the Standards Pertaining to Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Neither D&M nor Ryder Scott owns an interest in our properties and neither is employed on a contingent fee basis.

Our internal reserve engineer 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 is also our principal engineer. He has over 30 years of operations and industry experience and holds B.S. and Ph.D. degrees in Petroleum Engineering, in addition to a M.S. in Environmental and Planning Engineering, and is experienced in asset evaluation and management. 

Internal Controls Over Reserve Estimation Process

The primary inputs to the reserve estimation process are comprised of technical information, financial data, production data, and ownership interest. All field and reservoir technical information is assessed for validity when the internal reserve engineer holds technical meetings with our geoscientists, operations, and land personnel to discuss field performance and to validate future development plans. The other inputs used in the reserve estimation process, including, but not limited to, future capital expenditures, commodity price differentials, production costs, and ownership percentages are subject to internal controls over financial reporting and are assessed for effectiveness annually.

To further enhance the control environment over the reserve estimation process, our Strategic Planning and Reserves Committee, an independent committee of the Company’s board of directors (the “Board of Directors”), assists management and the Board of Directors with its oversight of the integrity of the determination of our oil and natural gas reserves and the work of the Reserve Engineering Firms. The Strategic Planning and Reserves Committee’s charter also specifies that it 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 Reserve Engineering Firms engaged by the Company (including resolution of material disagreements between management and the Reserve Engineering Firms regarding reserve determination) for the purpose of preparing or issuing an annual reserve report. The Strategic Planning and

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Reserves Committee shall review any proposed changes in the appointment of the Reserve Engineering Firms, determine the reasons for such proposal, and whether there have been any disputes between the Reserve Engineering Firms and management.

• Review the Company’s significant reserves engineering principles 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 Engineering Firms 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 Engineering Firms; (iii) evaluating the quality of the reserve estimates prepared by both the Reserve Engineering Firms 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 Engineering Firms’ estimates.

• If the Strategic Planning and Reserves Committee deems it necessary, it shall meet in executive session with the Reserve Engineering Firms 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 proved 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.

Capital Budget

Our Board approved operational capital expenditure budget for 2020 has been established at $975.0 million (the “2020 Capital Budget”), which includes running an average of eight to nine drilling rigs and an average of three completion crews. Approximately 10-15% of the 2020 Capital Budget is comprised of infrastructure and facilities capital. As part of our 2020 operated horizontal drilling program, we expect to drill approximately 165 gross operated wells and complete approximately 160 gross operated wells.

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, 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.

Drilling Activity

The following table sets forth our operated and non-operated drilling activity for the years ended December 31, 2019, 2018 and 2017. In the table, “gross” refers to the total wells in which we have a working interest and “net” refers to gross wells multiplied by our working interest therein. As defined by the SEC, the number of wells drilled refers to the number of wells completed at any time during the respective year, regardless of when drilling was initiated. For definitions of exploratory wells, development wells, productive wells, and non-productive wells, see “—Glossary of Certain Terms”. 

	Years Ended December 31,
	2019 (1)		2018		2017
	Gross	Net	Gross	Net	Gross	Net
Exploratory Wells - Productive	56	36.7	55	44.7	33	26.5
Exploratory Wells - Non-productive	—	—	—	—	1	1.0
Development Wells - Productive	15	11.6	15	12.8	15	10.7
Development Wells - Non-productive	—	—	—	—	—	—

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

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Productive Wells

The following table sets forth the number of productive crude oil and natural gas wells in which we owned an interest as of December 31, 2019.

	Crude Oil		Natural Gas		Total
	Gross	Net	Gross	Net	Gross	Net
Permian Basin - Operated	727	631.0	90	78.1	817	709.1
Permian Basin - Non-operated	119	13.1	63	3.0	182	16.1
Total Permian Basin	846	644.1	153	81.1	999	725.2
Eagle Ford Shale - Operated	609	548.0	2	1.8	611	549.8
Eagle Ford Shale - Non-operated	15	1.3	23	3.5	38	4.8
Total Eagle Ford Shale	624	549.3	25	5.3	649	554.6
Total	1,470	1,193.4	178	86.4	1,648	1,279.8

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Production Volumes, Average Sales Prices and Operating Costs

The following tables set forth certain information regarding the production volumes and average sales prices received for, and average production costs associated with, the Company’s sale of oil and natural gas for the periods indicated.

	Years Ended December 31,
	2019 (1)	2018	2017
Total production (2)
Oil (MBbls)	11,665	9,443	6,557
Natural gas (MMcf)	19,718	15,447	10,896
NGLs (MBbls)	135	—	—
Total barrels of oil equivalent (MBoe)	15,086	12,018	8,373
Daily production volumes by product (2)
Oil (Bbls/d)	31,957	25,871	17,964
Natural gas (Mcf/d)	54,021	42,321	29,852
NGLs (Bbls/d)	370	—	—
Total barrels of oil equivalent (Boe/d)	41,331	32,926	22,940
Daily production volumes by region (2)
Permian Basin	40,287	32,926	22,940
Eagle Ford Shale	1,044	—	—
Total barrels of oil equivalent (Boe/d)	41,331	32,926	22,940

	Years Ended December 31,
	2019 (1)		2018		2017
Revenues (in thousands)
Oil		$633,107		$530,898		$322,374
Natural gas	36,390		56,726		44,100
NGLs	2,075		—		—
Total revenues		$671,572		$587,624		$366,474
Operating costs (in thousands)
Lease operating expense		$91,827		$69,180		$49,907
Production taxes	42,651		35,755		22,396
Total operating costs		$134,478		$104,935		$72,303
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)		$54.27		$56.22		$49.16
Natural gas (per Mcf)	1.85		3.67		4.05
NGL (per Bbl)	15.37		—		—
Total (per Boe)		$44.52		$48.90		$43.77
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)		$53.31		$53.31		$47.78
Natural gas (per Mcf)	2.22		3.69		4.10
NGL (per Bbl)	15.37		—		—
Total (per Boe)		$44.27		$46.63		$42.76
Operating costs per Boe
Lease operating expense		$6.09		$5.76		$5.96
Production taxes	2.83		2.98		2.67
Total (per Boe)		$8.92		$8.74		$8.63

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

(2) The production associated with reserves acquired in the Carrizo Acquisition is presented on a three-stream basis and include NGLs, whereas, all other production volumes are on a two-stream basis.

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Major Customers

Our production is sold generally on month-to-month contracts at prevailing market prices. The following table presents customers that represented 10% or more of our total revenues for at least one of the periods presented: 

	Years Ended December 31,
	2019	2018	2017
Rio Energy International, Inc.	26%	28%	17%
Enterprise Crude Oil, LLC	19%	14%	18%
Plains Marketing, L.P.	15%	21%	29%
Shell Trading Company	10%	*	*

* - Less than 10% for the respective year.

Because alternative purchasers of oil and natural gas are readily available, we believe that the loss of any of these purchasers would not result in a material adverse effect on our ability to sell future oil and natural gas production. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security.

Leasehold Acreage

The following table shows our approximate developed and undeveloped leasehold acreage as of December 31, 2019.  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. 

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	Developed Acreage		Undeveloped Acreage		Total Acreage		Net Undeveloped Acreage Expiring
	Gross	Net	Gross	Net	Gross	Net	2020	2021	2022
Permian Basin (1)	137,786	97,352	36,136	19,432	173,922	116,784	13,765	1,903	981
Eagle Ford Shale (2)	75,864	64,146	14,696	12,088	90,560	76,234	1,357	—	300
Other (3)	2,123	174	79,615	57,070	81,738	57,244	—	1,234	48,504
Total	215,773	161,672	130,447	88,590	346,220	250,262	15,122	3,137	49,785

(1) Approximately 16%, 81% and 39% of the acreage expiring in 2020, 2021 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. The acreage expiring in 2020 is primarily in our Alpine High area, which was acquired as part of the Carrizo Acquisition, where, along with the other remaining acreage, we have no current development plans.

(2) Approximately 87% and 100% of the acreage expiring in 2020 and 2022, respectively, will be developed prior to expiration or extended by lease extension payments. We have no current development plans for the remaining expiring acreage as of December 31, 2019.

(3) Other includes non-core acreage principally located in Texas. We have no current development plans with this acreage as of December 31, 2019.

Our lease agreements generally terminate if producing wells have not been drilled on the acreage within their primary term or an extension thereof (a period that can be from three to five years depending on the area). The percentage of net undeveloped acreage expiring in 2020, 2021 and 2022 assumes that no producing wells have been drilled on acreage within their primary term or have been extended. We manage our lease expirations to ensure that we do not experience unintended material expirations. Our leasehold management efforts include scheduling drilling in order to hold leases by production or timely exercising our contractual rights to extend the terms of leases by continuous operations or the payment of lease extension payments and delay rentals. We may choose to allow some leases to expire that are no longer part of our development plans.

The proved undeveloped reserves associated with acreage expiring over the next three years are not material to the Company.

Other

Industry Segment and Geographic Information

For segment reporting purposes, the Company considers all of the current development and operating areas to be one reportable segment: the development and production of oil and natural gas. All of the Company’s assets are located within the United States and all operations are located within Texas. All of the production revenues generated from operations are contracted and sold to customers located in the United States.

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Title to Properties

The Company believes that the title to its 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’s properties are potentially subject to one or more of the following:

• royalties 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 reversionary interests existing under purchase agreements and leasehold assignments;

• liens that arise in the normal course of operations, such as those for unpaid taxes, statutory liens securing obligations to unpaid suppliers and contractors and contractual liens under operating agreements;

• pooling, unitization and communitization agreements, declarations and orders; and

• easements, restrictions, rights-of-way and other matters that commonly affect property.

To the extent that such burdens and obligations affect the Company’s rights to production revenues, these characteristics have been taken into account in calculating Callon’s net revenue interests and in estimating the size and value of its reserves. The Company believes that the burdens and obligations affecting our properties are typical within the industry for properties of the kind owned by Callon.

Seasonality of Business

Weather conditions and seasonality affect the demand for and prices of, oil and natural gas. Due to these fluctuations, results of operations for quarterly interim periods may not be indicative of the results realized on an annual basis.

Competition

The Company operates in the oil and natural gas industry, which is highly competitive. The Company’s business experiences strong competition from a number of parties that may range from small independent producers to major integrated companies. Competition affects the Company’s 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 maintains insurance against some, but not all, of the operating risks to which its business is exposed. While not all inclusive, the Company’s insurance policies generally protect against bodily injury and property damage, pollution and other environmental damages, employee benefits, employee injury and control of well insurance for its exploration and production operations.

The Company enters into master service agreements with its third-party contractors, including hydraulic fracturing contractors, in which they agree to indemnify the Company for injuries and deaths of the service provider’s employees, as well as contractors and subcontractors hired by the service provider. Similarly, the Company generally agrees to indemnify each third-party contractor against claims made by employees of the Company and the Company’s other contractors. Additionally, each party generally is responsible for damage to its own property. The Company re-evaluates the purchase of insurance, coverage limits and deductibles annually. Future insurance coverage for the oil and natural gas industry could increase in cost and may include higher deductibles or retentions. In addition, some forms of insurance may become unavailable in the future or unavailable on terms that are economically acceptable. While based on the Company’s risk analysis we believe that we are properly insured, no assurance can be given that the Company will be able to maintain insurance in the future at rates that it considers reasonable. In such circumstances, the Company may elect to self-insure or maintain only catastrophic coverage for certain risks in the future.

Corporate Offices

The Company’s headquarters are located in Houston, Texas, in a building with office space leased by the Company. We own office buildings in Natchez, Mississippi and Dilley and Pecos, Texas and lease and own offices in the Midland, Texas area. Because alternative locations to our leased spaces are readily available, the replacement of any of our leased offices would not result in material expenditures.

Employees

With the addition of employees from the Carrizo Acquisition that closed on December 20, 2019, Callon had 475 employees as of December 31, 2019. None of the Company’s employees are currently represented by a union, and the Company believes that it has good relations with its employees.

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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. Legislation and regulation affecting the entire oil and natural gas industry is continuously being reviewed for potential revision. Some of these requirements carry substantial penalties for failure to comply.

Exploration and Production.  Our operations are subject to federal, state and local regulations that include requirements for permits to drill and to conduct other operations and for provision of financial assurances (such as bonds and letters of credit) covering drilling and well operations. Other activities subject to regulation are:

• the location and spacing of wells;

• the method of drilling and completing and operating wells;

• the rate and method of production;

• the surface use and restoration of properties upon which wells are drilled and other exploration activities;

• notice to surface owners and other third parties;

• the venting or flaring of natural gas;

• the plugging and abandoning of wells;

• the discharge of contaminants into water and the emission of contaminants into air;

• the disposal of fluids used or other wastes obtained in connection with operations;

• the marketing, transportation and reporting of production; and

• the valuation and payment of royalties.

Our sales of oil and natural gas are affected by the availability, terms and cost of pipeline transportation. The price and terms for access to pipeline transportation remain subject to extensive federal and state regulation. If these regulations change, we could face higher transmission costs for our production and, possibly, reduced access to transmission capacity.

Various proposals and proceedings that might affect the petroleum industry are pending before Congress, federal administrative agencies such as the Federal Energy Regulatory Commission (“FERC”), various state and administrative agencies and legislatures, and the courts. Historically, the industry has been heavily regulated and we can offer you no assurance that the less stringent regulatory approach recently pursued by the FERC and state administrative agencies and Congress will continue nor can we predict what effect such proposals or proceedings may have on our operations.

We do not currently anticipate that compliance with existing laws and regulations governing exploration and production will have a significantly adverse effect upon our capital expenditures, earnings or competitive position.

Environmental Matters and Regulation. Our oil and natural gas exploration, development and production operations are subject to stringent laws and regulations governing the discharge of materials into the environment or otherwise relating to environmental protection. Numerous federal, state and local governmental agencies, such as the U.S. Environmental Protection Agency (the “EPA”), issue regulations which often require difficult and costly compliance measures. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, wetlands, ecologically sensitive and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations or relating to our owned or operated facilities. Violations of environmental laws could result in administrative, civil or criminal fines and injunctive relief. The strict and joint and several liability nature of certain such laws and regulations could impose liability upon us regardless of fault. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons, air emissions or other waste products into the environment. Changes in environmental laws and regulations occur frequently, and any changes that result in more stringent and costly pollution control or waste handling, storage, transport, disposal or cleanup requirements could materially adversely affect our operations and financial position, as well as the oil and natural gas industry in general. In recent years, the oil and natural gas exploration and production industry has been the subject of increasing scrutiny and regulation by environmental authorities. Our management believes that we are in substantial compliance with applicable environmental laws and regulations and we have not experienced any material adverse effect from compliance with these environmental requirements. Although such laws and regulations can increase the cost of planning, designing, installing and operating our facilities, it is anticipated that, absent the occurrence of an extraordinary event, compliance with them will not have a material effect upon our operations, capital expenditures, earnings or competitive position in the marketplace.

Waste Handling. The Resource Conservation and Recovery Act (“RCRA”), as amended, and comparable state statutes and regulations promulgated thereunder, affect oil and natural gas exploration, development and production activities by imposing requirements regarding the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. With federal approval, the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent

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requirements. Although most wastes associated with the exploration, development and production of oil and natural gas are exempt from regulation as hazardous wastes under RCRA and its state analogs, it is possible that some wastes we generate presently or in the future may be subject to regulation under RCRA and state analogs. Additionally, we cannot assure you that the EPA or state or local governments will not adopt more stringent requirements for the handling of non-hazardous wastes or categorize some non-hazardous wastes as hazardous for future regulation. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Additionally, following the filing of a lawsuit in the U.S. District Court for the District of Columbia in May 2016 by several non-governmental environmental groups against the EPA for the agency’s failure to timely assess its RCRA Subtitle D criteria regulations for oil and gas wastes, the EPA and the environmental groups entered into an agreement that was finalized in a consent decree issued by the District Court on December 28, 2016. Under the decree, the EPA was required to propose no later than March 15, 2019, a rulemaking for revision of certain Subtitle D criteria regulations pertaining to oil and gas wastes or sign a determination that revision of the regulations was not necessary. On April 23, 2019, the EPA determined that a revision of the regulations was not necessary. If the EPA proposes a rulemaking for revised oil and gas waste regulations in the future, any such changes in the laws and regulations could have a material adverse effect on our capital expenditures and operating expenses.

Administrative, civil and criminal penalties can be imposed for failure to comply with waste handling requirements. We believe that we are in substantial compliance with applicable requirements related to waste handling, and that we hold all necessary and up-to-date permits, registrations and other authorizations to the extent that our operations require them under such laws and regulations. Although we do not believe the current costs of managing our wastes, as presently classified, to be significant, any legislative or regulatory reclassification of wastes associated with oil and natural gas exploration and production could increase our costs to manage and dispose of such wastes.

Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response, Compensation and Liability Act (“CERCLA”), imposes joint and several liability for costs of investigation and remediation and for natural resource damages without regard to fault or legality of the original conduct, on certain classes of persons with respect to the release into the environment of substances designated under CERCLA as hazardous substances. These classes of persons, or potentially responsible parties (“PRPs”) include the current and past owners or operators of a site where the release occurred and anyone who disposed or arranged for the disposal of a hazardous substance found at the site. CERCLA also authorizes the EPA and, in some instances, third parties to take actions in response to threats to public health or the environment and to seek to recover from the PRPs the costs of such action. Many states have adopted comparable or more stringent state statutes.

Although CERCLA generally exempts “petroleum” from the definition of hazardous substance, in the course of our operations, we have generated and will generate wastes that may fall within CERCLA’s definition of hazardous substance and may have disposed of these wastes at disposal sites owned and operated by others. Comparable state statutes may not provide a comparable exemption for petroleum. We may also be the owner or operator of sites on which hazardous substances have been released. To our knowledge, neither we nor our predecessors have been designated as a PRP by the EPA under CERCLA; we also do not know of any prior owners or operators of our properties that are named as PRPs related to their ownership or operation of such properties. In the event contamination is discovered at a site on which we are or have been an owner or operator or to which we sent hazardous substances, we could be liable for the costs of investigation and remediation and natural resources damages.

We currently own, lease, or operate numerous properties that have been used for oil and natural gas exploration and production for many years. Although we believe we have utilized operating, waste disposal, and water disposal practices that were standard in the industry at the time, hazardous substances, wastes or hydrocarbons may have been released on or under the properties owned or leased by us, or on or under other locations, including offsite locations, where such substances have been taken for disposal. In addition, some of these properties have been operated by third parties or by previous owners or operators whose treatment and disposal of hazardous substances, wastes, or hydrocarbons were not under our control. These properties and the substances disposed or released on them may be subject to CERCLA, RCRA and analogous state laws. In the future, we could be required to remediate property, including groundwater, containing or impacted by previously disposed wastes (including wastes disposed or released by prior owners or operators, or property contamination or groundwater contamination by prior owners or operators) or to perform remedial plugging operations to prevent future or mitigate existing contamination.

Water Discharges. The Federal Water Pollution Control Act of 1972, as amended, also known as the Clean Water Act, the Safe Drinking Water Act, the Oil Pollution Act (“OPA”), and analogous state laws and regulations promulgated thereunder impose restrictions and strict controls regarding the unauthorized discharge of pollutants, including produced waters and other gas and oil wastes, into navigable waters of the United States (a term broadly defined to include, among other things, certain wetlands), as well as state waters for analogous state programs. The discharge of pollutants into regulated waters is prohibited, except in accordance with the terms of a permit issued by the EPA or applicable state analog. The Clean Water Act and regulations implemented thereunder also prohibit the discharge of dredge and fill material into regulated waters, including jurisdictional wetlands, unless authorized by an appropriately issued permit from the U.S. Army Corps of Engineers. The EPA issued a final rule on the federal jurisdictional reach over waters of the United States in 2015, which was repealed by the EPA on October 22, 2019. On January 23, 2020, the EPA and the U.S. Army Corps of Engineers issued a final rule re-defining the term “waters of the United States” as applied under the Clean Water Act and narrowing the scope of waters subject to

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federal regulation. The rule is the subject of various legal challenges, creating uncertainty regarding federal jurisdiction over waters of the United States.

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, and comparable state and local laws and regulations, regulate emissions of various air pollutants through the issuance of permits and the imposition of other requirements. The EPA has developed, and continues to develop, stringent regulations governing emissions of air pollutants at specified sources. New facilities may be required to obtain permits before work can begin, and modified and existing facilities may be required to obtain additional permits. As a result, we may need to incur capital costs in order to remain in compliance. Obtaining or renewing permits also has the potential to delay the development of oil and natural gas projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties and seek injunctive relief for non-compliance with air permits or other requirements of the federal Clean Air Act 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.

On June 3, 2016, the EPA expanded its regulatory coverage in the oil and natural gas industry with additional regulated equipment categories, and the addition of new rules limiting methane emissions from new or modified sites and equipment. Although the EPA attempted to suspend enforcement of the methane rule, this action was ruled improper by the U.S. Court of Appeals for the D.C. Circuit on July 2, 2017. Subsequently, in September 2018, the EPA issued a proposed rulemaking that could substantially change the obligations associated with methane emissions, limiting obligations for the oil and natural gas industry. Separately, in August 2019, the EPA issued proposed amendments that would that would rescind requirements related to the regulation of methane emissions from the oil and natural gas industry. Neither rulemaking has been finalized and, therefore, future obligations continue to remain uncertain under the Clean Air Act.

Climate Change. Numerous reports from scientific and governmental bodies such as the United Nations Intergovernmental Panel on Climate Change have expressed heightened concerns about the impacts of human activity, especially fossil fuel combustion, on the global climate. In turn, governments and civil society are increasingly focused on limiting the emissions of GHGs, including emissions of carbon dioxide from the use of oil and natural gas.

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the so-called “Paris Agreement,” which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal will become effective on November 4, 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. In addition, legislation has from time to time been introduced in Congress that would establish measures restricting GHG emissions in the United States, and a number of states have begun taking actions to control and/or reduce emissions of GHGs.

Any legislation or regulatory programs at the federal, state, or city levels designed to reduce GHG emissions could increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. Moreover, incentives to conserve energy or use alternative energy sources, such as policies designed to increase utilization of zero-emissions or electric vehicles, as a means of addressing climate change could reduce demand for the oil and natural gas we produce.

In the absence of comprehensive federal legislation on GHG emission control, the EPA attempted to require the permitting of GHG emissions. Although the Supreme Court struck down the permitting requirements, it upheld the EPA’s authority to control GHG emissions when a permit is required due to emissions of other pollutants.

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The EPA has established GHG reporting requirements for certain sources in the petroleum and natural gas industry, requiring those sources to monitor, maintain records on, and annually report their GHG emissions. Although these requirements do not limit the amount of GHGs that can be emitted, they do require us to incur costs to monitor, keep records of, and report GHG emissions associated with our operations.

Parties concerned about the potential effects of climate change have also directed their attention at sources of financing for energy companies, which has resulted in certain financial institutions, funds and other capital providers restricting or eliminating their investment in oil and natural gas activities. In addition, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. Although our business is not a party to any such litigation, we could be named in actions making similar allegations, which could lead to costs and materially impact our financial condition in an adverse way.

Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects.

Regulation of Hydraulic Fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons, particularly natural gas, from tight formations, including shales. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production. The federal Safe Drinking Water Act (“SDWA”) regulates the underground injection of substances through the Underground Injection Control (“UIC”) program. Hydraulic fracturing is generally exempt from regulation under the UIC program, and the hydraulic fracturing process is typically regulated by state oil and gas commissions and not at the federal level, as the SDWA expressly excludes regulation of these fracturing activities (except where diesel is a component of the fracturing fluid, as further discussed below). Legislation to amend the SDWA to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and require federal permitting and regulatory control of hydraulic fracturing has been proposed in past legislative sessions but has not passed.

The EPA, however, issued guidance on permitting hydraulic fracturing that uses fluids containing diesel fuel under the UIC program, specifically as “Class II” UIC wells. In  December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources, concluding that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources “under some circumstances,” including water withdrawals for fracturing in times or areas of low water availability; surface spills during the management of fracturing fluids, chemicals or produced water; injection of fracturing fluids into wells with inadequate mechanical integrity; injection of fracturing fluids directly into groundwater resources; discharge of inadequately treated fracturing wastewater to surface waters; and disposal or storage of fracturing wastewater in unlined pits. This report could result in additional regulatory scrutiny that could make it more difficult to perform hydraulic fracturing and increase our costs of compliance and business. Further, on June 28, 2016, the EPA published an effluent limit guideline final rule prohibiting the discharge of wastewater from onshore unconventional oil and natural gas extraction facilities to publicly owned wastewater treatment plants.

On June 3, 2016, the EPA adopted regulations under the federal Clean Air Act that establish new air emission controls for oil and natural gas production and natural gas processing operations. Specifically, the EPA’s rule package included New Source Performance Standards (“NSPS”) for hydraulically fractured natural gas and oil wells to address emissions of sulfur dioxide, volatile organic compounds (“VOCs”) and methane, with a separate set of emission standards to address hazardous air pollutants frequently associated with oil and natural gas production and processing activities. The final rule sought to achieve a 95% reduction in VOCs and methane emitted by requiring the use of reduced emission completions or “green completions” on all hydraulically-fractured gas and newly constructed or refractured oil wells. The rules also established specific new requirements regarding emissions from compressors, controllers, dehydrators, storage tanks and other production equipment. Notably, on October 15, 2018, the EPA published a proposed rule that would make a series of revisions to the 2016 NSPS; these revisions have yet to be finalized. Separately, on August 28, 2019, the EPA published a proposed rule that would that would rescind requirements related to the regulation of methane emissions from the oil and gas industry; these revisions have yet to be finalized.

On March 20, 2015, the U.S. Bureau of Land Management (the “BLM”) finalized a rule regulating hydraulic fracturing activities on federal lands, including requirements for disclosure, wellbore integrity and handling of flowback water; however, on December 29, 2017, the BLM issued a rescission of the hydraulic fracturing rule. This rescission and the rule as promulgated are subject to ongoing litigation. Additionally, on November 18, 2016, the BLM finalized limitations on methane emissions from venting and flaring and leaking equipment from oil and natural gas activities on public lands, but on September 28, 2018 issued a final rule repealing certain provisions of the 2016 rule and reinstating the pre-2016 regulations; a lawsuit challenging the September 2018 rule revision is pending.

Several states, including Texas, and some municipalities, have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, Texas law requires that the well operator disclose the list of chemical ingredients subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) for disclosure on a website and also file the list of chemicals with the Texas Railroad

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Commission (the “RRC”) with the well completion report. The total volume of water used to hydraulically fracture a well must also be disclosed to the public and filed with the RRC.

Additionally, some states, localities and local regulatory districts have adopted or have considered adopting regulations to limit, and in some cases impose a moratorium on, hydraulic fracturing or other restrictions on drilling and completion operations, including requirements regarding casing and cementing of wells; testing of nearby water wells; or restrictions on access to, and usage of, water.  Further, there has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, impacts on drinking water supplies, use of water and the potential for impacts to surface water, groundwater and the environment generally. A number of lawsuits and enforcement actions have been initiated across the U.S. implicating hydraulic fracturing practices. If new laws or regulations that significantly restrict hydraulic fracturing are adopted, such laws could make it more difficult or costly for us to perform fracturing to stimulate production from tight formations as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings based on allegations of harm. In addition, if hydraulic fracturing is further regulated at the federal or state level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements and also to attendant permitting delays and potential increases in costs. Such legislative changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of potential federal or state legislation governing hydraulic fracturing. In light of concerns about seismic activity being triggered by the injection of produced waters into underground wells, certain regulators are also considering additional requirements related to seismic safety for hydraulic fracturing activities. A 2015 U.S. Geological Survey report identified eight states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and gas extraction. Any regulation that restricts our ability to dispose of produced waters or increases the cost of doing business could cause curtailed or decreased demand for our services and have a material adverse effect on our business.

Surface Damage Statutes (“SDAs”). In addition, a number of states and some tribal nations have enacted SDAs. These laws are designed to compensate for damage caused by oil and gas development operations. Most SDAs contain entry notification and negotiation requirements to facilitate contact between operators and surface owners/users. Most also contain binding requirements for payments by the operator to surface owners/users in connection with exploration and operating activities in addition to bonding requirements to compensate for damages to the surface as a result of such activities. Costs and delays associated with SDAs could impair operational effectiveness and increase development costs.

National Environmental Policy Act.  Oil and natural gas exploration and production activities on federal lands may be subject to the National Environmental Policy Act (“NEPA”), which requires federal agencies, including the Department of Interior, to evaluate major agency actions having the potential to significantly impact the environment. In the course of such evaluations, an agency will prepare an Environmental Assessment that assesses the potential direct, indirect and cumulative impacts of a proposed project and, if necessary, will prepare a more detailed Environmental Impact Statement that may be made available for public review and comment. Recent litigation by environmental non-governmental organizations has alleged that the Environmental Assessments for certain oil and natural gas projects violated NEPA by failing to account for climate change and the greenhouse gas emissions impacts of such projects. On January 10, 2020, the Council on Environmental Quality issued a proposed rule designed to streamline approvals for projects under NEPA. Among other revisions, the proposed rule would redefine environmental “effects” or “impacts” as the effects “that are reasonably foreseeable and have a reasonably close causal relationship to the proposed action or alternatives.” The proposed rule would also eliminate the current “direct,” “indirect,” or “cumulative” categories of effects. This rulemaking process is ongoing. To the extent that our current exploration and production activities, as well as proposed exploration and development plans, on 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. 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 must also designate the species’ critical habitat and suitable habitat as part of the effort to ensure survival of the species. A final rule amending how critical habitat and suitable habitat areas are designated under the ESA was finalized by the U.S. Fish and Wildlife Service in 2016. 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. 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.

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The availability, terms and cost of transportation significantly affect sales of oil and natural gas. The interstate transportation of oil and natural gas is subject to federal regulation, by the FERC which regulates the terms, conditions and rates for interstate transportation and storage service and various other matters. State regulations govern the rates, terms, and conditions of service associated with access to interstate oil and natural gas pipeline transportation. FERC’s regulations for interstate oil and natural gas transportation in some circumstances may also affect the intrastate transportation of oil and natural gas.

Although oil and natural gas sales prices are currently unregulated, the federal government historically has been active in the area of oil and natural gas sales regulation. We cannot predict whether new legislation to regulate oil and natural gas sales might be proposed, what proposals, if any, might actually be enacted by Congress or the various state legislatures, and what effect, if any, the proposals might have on our operations. Sales of natural gas, condensate, oil and natural gas liquids are not currently regulated and are made at market prices.

Exports of US Oil Production and Natural Gas Production. In December 2015, the federal government ended its decades-old prohibition of exports of oil produced in the lower 48 states of the US. As a result, exports of U.S. oil have increased significantly, reinforcing the general perception in the industry that the end of the U.S. export ban was positive for producers of U.S. oil. In addition, the U.S. Department of Energy authorizes exports of natural gas, including exports of natural gas by pipelines connecting U.S. natural gas production to pipelines in Mexico, and the export of liquefied natural gas (“LNG”) through LNG export facilities, the construction and operation of which are regulated by FERC. Since 2016, natural gas produced in the lower 48 states of the U.S. has been exported as LNG from export facilities in the U.S. Gulf Coast region. LNG export capacity has steadily increased in recent years, and is expected to continue increasing due to numerous export facilities that are currently being developed. The industry generally believes that this sustained growth in exports will be a positive development for producers of U.S. natural gas.

Drilling and Production. Our operations are subject to various types of regulation at the federal, state and local level. These types of regulation include requiring permits for the drilling of wells, drilling bonds and reports concerning operations. The state, and some counties and municipalities, in which we operate also regulate one or more of the following:

• the location of wells;

• the method of drilling and casing wells;

• the timing of construction or drilling activities, including seasonal wildlife closures;

• the rates of production or “allowables”;

• the surface use and restoration of properties upon which wells are drilled;

• the plugging and abandoning of wells; and

• notice to, and consultation with, surface owners and other third parties.

State laws regulate the size and shape of drilling and spacing units or proration units governing the pooling of oil and natural gas properties. Some states allow forced pooling or integration of tracts to facilitate exploration while other states rely on voluntary pooling of lands and leases. In some instances, forced pooling or unitization may be implemented by third parties and may reduce our interest in the unitized properties. In addition, state conservation laws establish maximum rates of production from oil and natural gas wells, generally prohibit the venting or flaring of natural gas and impose requirements regarding the ratability of production. These laws and regulations may limit the amount of oil and natural gas we can produce from our wells or limit the number of wells or the locations at which we can drill. Moreover, each state generally imposes a production or severance tax with respect to the production and sale of oil, natural gas and natural gas liquids within its jurisdiction. States do not regulate wellhead prices or engage in other similar direct regulation, but we cannot assure you that they will not do so in the future. The effect of such future regulations may be to limit the amounts of oil and natural gas that may be produced from our wells, negatively affecting the economics of production from these wells or to limit the number of locations we can drill.

Federal, state and local regulations provide detailed requirements for the abandonment of wells, closure or decommissioning of production facilities and pipelines and for site restoration in areas where we operate. The U.S. Army Corps of Engineers and many other state and local authorities also have regulations for plugging and abandonment, decommissioning and site restoration. Some state agencies and municipalities require bonds or other financial assurances to support those obligations.

Natural Gas Sales and Transportation. Historically, federal legislation and regulatory controls have affected the price of the natural gas we produce and the manner in which we market our production and have it transported. FERC has jurisdiction over the transportation and sale for resale of natural gas in interstate commerce by natural gas companies under the Natural Gas Act of 1938 (“NGA”) and the Natural Gas Policy Act of 1978 (“NGPA”). Since 1978, various federal laws have been enacted which have resulted in the complete removal of all price and non-price controls for “first sales,” which include all of our sales of our own production.

Under the Energy Policy Act of 2005 (“EPAct”) Congress amended the NGA and NGPA to give FERC substantial enforcement authority to prohibit the manipulation of natural gas markets and enforce its rules and orders, including the ability to assess civil penalties up to $1.0 million per day for each violation. This maximum penalty authority has been and will continue to be adjusted periodically to account for inflation. EPAct also amended the NGA to authorize FERC to “facilitate 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

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annually to FERC concerning their natural gas sales and purchases. FERC requires any wholesale market participant that sells 2.2 million MMBtus or more annually in “reportable” natural gas sales to provide a report, known as FERC Form 552, to FERC. Reportable natural gas sales include sales of natural gas that utilize a daily or monthly gas price index, contribute to index price formation, or could contribute to index price formation, such as fixed price transactions for next-day or next-month delivery.

FERC also regulates interstate natural gas transportation rates, terms and conditions of service, and the terms under which we as a shipper may use interstate natural gas pipeline capacity, which affects the marketing of natural gas that we produce, as well as the revenues we receive for sales of our natural gas and for the release of our excess, if any, natural gas pipeline capacity. In 1985, FERC began promulgating a series of orders, regulations and rule makings that significantly fostered competition in the business of transporting and marketing gas. Today, interstate natural gas pipeline companies are required to provide non-unduly discriminatory transportation services to all shippers, regardless of whether such shippers are affiliated with an interstate pipeline company. FERC’s initiatives have led to the development of a competitive, open access market for natural gas purchases, sales, and transportation that permits all purchasers of natural gas to buy gas directly from third-party sellers other than pipelines. However, the natural gas industry historically has been very heavily regulated; therefore, 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-unduly discriminatory basis at cost-based rates or negotiated rates, both of which are subject to FERC approval. The FERC also allows jurisdictional gas pipeline companies to charge market-based rates if the transportation market at issue is sufficiently competitive. The FERC-regulated tariffs, under which interstate pipelines provide such open-access transportation service, contain strict limits on the means by which a shipper releases its pipeline capacity to another potential shipper, which provisions require compliance with FERC’s “shipper-must-have-title” rule. Violations by a shipper (i.e., a pipeline customer) of FERC’s capacity release rules or shipper-must-have-title rule could subject a shipper to substantial penalties from FERC.

With respect to its regulation of natural gas pipelines under the NGA, FERC has not generally required the applicant for construction of a new interstate natural gas pipeline to provide information concerning the GHG emissions resulting from the activities of the proposed pipeline’s customers. In August 2017, the U.S. Circuit Court of Appeals for the DC Circuit issued a decision remanding a natural gas pipeline certificate application to FERC, and required FERC to revise its environmental impact statement for the proposed pipeline to analyze potential GHG emission from the specific downstream power plants that the pipeline was designed to serve. To date, FERC has declined to analyze potential upstream GHG emissions that could result from the activities of natural gas producers and marketers, like the Company, to be served by proposed interstate natural gas pipeline projects. However, the scope of FERC’s obligation to analyze the environmental impacts of proposed interstate natural gas pipeline projects, including the upstream indirect impacts of related natural gas production activity, remains subject to ongoing litigation and contested administrative proceedings at the FERC and in the courts.

Gathering service, which occurs on pipeline facilities located upstream of FERC-jurisdictional interstate transportation services, is regulated by the states onshore and in state waters. Under NGA section 1(b), gathering facilities are exempt from FERC’s jurisdiction. FERC has set forth a general test for determining whether facilities perform a non-jurisdictional gathering function or a jurisdictional transmission function, and FERC applies this test on a case-by-case basis. Depending on changes in the function performed by particular pipeline facilities, FERC has in the past reclassified certain FERC-jurisdictional transportation facilities as non-jurisdictional gathering facilities and FERC has reclassified certain non-jurisdictional gathering facilities as FERC-jurisdictional transportation facilities. Any such changes could result in an increase to our costs of transporting gas to point-of-sale locations.

The pipelines used to gather and transport natural gas being produced by the Company are also subject to regulation by the U.S. Department of Transportation (“DOT”) under the Natural Gas Pipeline Safety Act of 1968, as amended, the Pipeline Safety Act of 1992, as reauthorized and amended (“Pipeline Safety Act”), and the Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011.  The DOT Pipeline and Hazardous Materials Safety Administration (“PHMSA”) has established a risk-based approach to determine which gathering pipelines are subject to regulation and what safety standards regulated gathering pipelines must meet. In addition, PHMSA had initially considered regulations regarding, among other things, the designation of additional high consequence areas along pipelines, minimum requirements for leak detection systems, installation of emergency flow restricting devices, and revision of valve spacing requirements. In October 2019, PHMSA finalized new safety regulations for hazardous liquid pipelines, including a requirement that operators inspect affected pipelines following extreme weather events or natural disasters, that all hazardous liquid pipelines have a system for detecting leaks and that pipelines in high consequence areas be capable of accommodating in-line inspection tools within twenty years. In addition, PHMSA is in the process of finalizing a rulemaking with respect to gathering lines, but the contents and timing of any final rule for gathering lines are uncertain.

Oil 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 and costs of transportation. The rates, terms, and conditions applicable to the interstate transportation of oil and natural gas liquids by pipelines are regulated by FERC under the Interstate Commerce Act (“ICA”). FERC has implemented a simplified and generally applicable ratemaking methodology for interstate

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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. Insofar as effective interstate and intrastate rates are equally applicable to all comparable shippers, we believe that the regulation of oil and natural gas liquid transportation rates will not affect our operations in any materially different way than such regulation will affect the operations of our competitors.

Further, interstate common carrier oil pipelines must provide service on a non-duly discriminatory basis under the ICA, which is administered by FERC. Under this open access standard, common carriers must offer service to all shippers requesting service on the same terms and under the same rates. When oil pipelines operate at full capacity, access is governed by prorationing provisions set forth in the pipelines’ published tariffs. Accordingly, we believe that access to oil pipeline transportation services generally will be available to us to the same extent as to our competitors.

In addition, FERC issued a declaratory order in November 2017, involving a marketing affiliate of an oil pipeline, which held that certain arrangements between an oil pipeline and its marketing affiliate would violate the ICA’s anti-discrimination provisions. FERC held that providing transportation service to affiliates at what is essentially the variable cost of the movement, while requiring non-affiliated shippers to pay the filed tariff rate, would violate the ICA. Rehearing has been sought of this FERC order by various parties. Due to the pending rehearing of the order and its recency, the Company cannot currently determine the impact this FERC order may have on oil pipelines, their marketing affiliates, and the price of oil and other liquids transported by such pipelines.

Any transportation of the Company’s oil, natural gas liquids and purity components (ethane, propane, butane, iso-butane, and natural gasoline) by rail is also subject to regulation by the DOT’s PHMSA and the DOT’s Federal Railroad Administration (“FRA”) under the Hazardous Materials Regulations at 49 CFR Parts 171-180, including Emergency Orders by the FRA regulations initially established on May 8, 2015 by PHMSA, arising due to the consequences of train accidents and the increase in the rail transportation of flammable liquids; PHMSA regulations were subsequently amended to remove certain requirements on September 25, 2018.

State Regulation. Texas regulates the drilling for, and the production, gathering and sale of, oil and natural gas, including imposing severance taxes and requirements for obtaining drilling permits. Texas currently imposes a 4.6% severance tax on oil production and a 7.5% severance tax on natural gas production. States also regulate the method of developing new fields, the spacing and operation of wells and the prevention of waste of oil and natural gas resources. States may regulate rates of production and may establish maximum daily production allowables from oil and natural gas wells based on market demand or resource conservation, or both. States do not regulate wellhead prices or engage in other similar direct economic regulation, but we cannot assure you that they will not do so in the future. The effect of these regulations may be to limit the amount of oil and natural gas that may be produced from our wells and to limit the number of wells or locations we can drill.

The petroleum industry is also subject to compliance with various other federal, state and local regulations and laws. Some of those laws relate to resource conservation and equal employment opportunity. We do not believe that compliance with these laws will have a material adverse effect on us. 

Financial Regulations, Including Regulations Enacted Under the Dodd-Frank Act. The U.S. Commodities and Futures Exchange Commission (“CFTC”) holds authority to monitor certain segments of the physical and futures energy commodities market including oil and natural gas. With regard to physical purchases and sales of natural gas and other energy commodities, and any related hedging activities that the Company undertakes, the Company is thus required to observe anti-market manipulation and disruptive trading practices laws and related regulations enforced by the FERC and/or the CFTC. The CFTC also holds substantial enforcement authority, including the ability to assess civil penalties.

Congress adopted comprehensive financial reform legislation in 2010, establishing federal oversight and regulation of the over-the-counter derivative market and entities that participate in that market. The legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (“Dodd-Frank Act”), required the CFTC and the U.S. Securities and Exchange Commission (“SEC”) to promulgate rules and regulations implementing the legislation, including regulations that affecting derivatives contracts that the Company uses to hedge its exposure to price volatility.

While the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas remain pending, including a proposal to set position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents. The CFTC also has proposed, but not yet finalized, a rule regarding the capital posting requirements for swap dealers and major swap market participants. The Company cannot, at this time, predict the timing or contents of any final rules the CFTC may enact with regard to either 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

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below the new limits by June 23, 2021), naming oil and gas as a high hazard industry and requirements for a safety and health management system. In addition, OSHA’s hazard communication standard, the EPA community right-to-know regulations under Title III of the federal Superfund Amendment and Reauthorization Act and comparable state statutes require that information be maintained concerning hazardous materials used or produced in our operations, and that this information be provided to employees, state and local government authorities and citizens.

Commitments and Contingencies

The Company’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 will not 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 included, and claims for damages to property, employees, other persons, and the environment resulting from the Company’s operations could have on its activities. See “Note 17 - Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information.

Available Information

We make available free of charge on our website (www.callon.com) our Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other filings pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934, and amendments to such filings, as soon as reasonably practicable after each are electronically filed with, or furnished to, the SEC.

We also make available within the “About Callon” section of our website our Code of Business Conduct and Ethics, Corporate Governance Guidelines, and Audit, Compensation, Strategic Planning and Reserves, and Nominating and Corporate Governance Committee Charters, which have been approved by our Board of Directors. We will make timely disclosure on our website of any change to, or waiver from, the Code of Business Conduct and Ethics for our principal executive and senior financial officers. A copy of our Code of Business Conduct and Ethics is also available, free of charge by writing us at: General Counsel, Callon Petroleum Company, 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042. 

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ITEM 1A.  Risk Factors

Risks Related to the Oil & Natural Gas Industry

Oil and natural gas prices are volatile, and substantial or extended declines in prices may adversely affect our results of operations and financial condition. Our success is highly dependent on prices for oil and natural gas, which have in recent years been, and we expect will continue to be, extremely volatile. During the five years ended December 31, 2019, NYMEX WTI prices ranged from a high of $77.41 per barrel on June 27, 2018 to a low of $26.19 per barrel on February 11, 2016, and NYMEX Henry Hub prices ranged from a high of $6.24 per MMBtu on January 2, 2018 to a low of $1.49 per MMBtu on March 4, 2016. The prices of oil and natural gas depend on factors we cannot control, such as macro-economic conditions, levels of production, domestic and worldwide inventories, demand for oil and natural gas, the capacity of U.S. and international refiners to use U.S. supplies of oil, natural gas and NGLs, relative price and availability of alternative forms of energy, actions by non-governmental organizations, OPEC and other countries, legislative and regulatory actions, technology developments impacting energy consumption and energy supply, and weather. These factors make it extremely difficult to predict future oil, natural gas and NGLs price movements with any certainty. We make price assumptions that are used for planning purposes, and a significant portion of our cash outlays, including rent, salaries and noncancelable capital commitments, are largely fixed in nature. Accordingly, if commodity prices are below the expectations on which these commitments were based, our financial results are likely to be adversely and disproportionately affected because these cash outlays are not variable in the short term and cannot be quickly reduced to respond to unanticipated decreases in commodity prices.

In general, prices of oil, natural gas, and NGLs affect the following aspects of our business:

• our revenues, cash flows, earnings and returns;

• our ability to attract capital to finance our operations and the cost of the capital;

• the amount we are allowed to borrow under our Credit Facility;

• the profit or loss we incur in exploring for and developing our reserves; and

• the value of our oil and natural gas properties.

A substantial or extended decline in commodity prices may also reduce the amount of oil and natural gas that we can produce economically and cause a significant portion of our development projects to become uneconomic. This may result in our having to make significant downward adjustments to our estimated proved reserves. A reduction in production could also result in a shortfall in expected cash flows and require us to reduce capital spending, which could negatively affect our ability to replace our production and our future rate of growth, or require us to borrow funds to cover any such shortfall, which we may be unable to obtain at such time on satisfactory terms. As a result, a substantial or extended decline in commodity prices may materially and adversely affect our future business, financial condition, results of operations, liquidity or ability to finance planned capital expenditures.

If oil and natural gas prices remain depressed for extended periods of time, we may be required to make significant downward adjustments to the carrying value of our oil and natural gas properties. Under the full cost method, which we use to account for our oil and natural gas properties, the net capitalized costs of our oil and natural gas properties may not exceed the PV-10 of our estimated proved reserves, using the 12-Month Average Realized Price, plus the lower of cost or fair market value of our unproved properties. If such net capitalized costs exceed this limit, we must charge the amount of the excess to earnings. This type of charge will not affect our cash flows, but will reduce the book value of our stockholders’ equity. We review the carrying value of our properties quarterly and once incurred, a write-down of oil and natural gas properties is not reversible at a later date, even if prices increase. See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements as well as the Supplemental Information on Oil and Natural Gas Operations for additional information.

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.

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, 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, during periods in which the levels of exploration and production increase, the demand for, and wages and costs of, drilling rig crews and other experienced personnel, oilfield services and equipment typically also increase, while the quality of these services and equipment may suffer.

All of our producing properties are located in the Permian Basin of West Texas and the Eagle Ford Shale 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

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companies that have a more diversified portfolio of properties, 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, 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.

We may be unable to integrate successfully the operations of recent acquisitions with our operations, and we may not realize all the anticipated benefits of these acquisitions. We have completed, and may in the future complete, acquisitions that include undeveloped acreage. We can offer no assurance that we will achieve the desired profitability from our acquisitions, including the Carrizo Acquisition, or from any acquisitions we may complete in the future. In addition, failure to integrate recent and future acquisitions successfully could adversely affect our financial condition and results of operations.

Our acquisitions, including the recently completed Carrizo Acquisition, may involve numerous risks, including those relating to:

• operating a larger, more complex combined organization and adding operations;

• assimilating the assets and operations of the acquired business, especially if the assets acquired are in a new geographic area;

• acquired oil and natural gas reserves not being of the anticipated magnitude or as developed as anticipated;

• the loss of significant key employees, including from the acquired business;

• the inability to obtain satisfactory title to the assets we acquire;

• a decrease in our liquidity if we use a portion of our available cash to finance acquisitions;

• a significant increase in our interest expense or financial leverage if we incur additional debt to finance acquisitions;

• the diversion of management’s attention from other business concerns, which could result in, among other things, performance shortfalls;

• the failure to realize expected profitability or growth;

• the failure to realize expected synergies and cost savings;

• coordinating geographically disparate organizations, systems and facilities;

• coordinating or consolidating corporate and administrative functions;

• inconsistencies in standards, controls, procedures and policies; and

• integrating relationships with customers, vendors and business partners.

Further, unexpected costs and challenges may arise whenever businesses with different operations or management are combined, and we may experience unanticipated delays in realizing the benefits of an acquisition. With respect to the Carrizo Acquisition in particular, we have incurred a number of costs associated with completing the Carrizo acquisition and expect to continue to incur significant costs to integrate the business of Carrizo. The elimination of duplicative costs, as well as the realization of other efficiencies related to the integration of our two companies, may not initially offset integration-related costs or achieve a net benefit in the near term or at all.

If we consummate any future acquisition, our capitalization and results of operation may change significantly, and you may not have the opportunity to evaluate the economic, financial and other relevant information that we will consider in evaluating future acquisitions. The inability to effectively manage the integration of acquisitions could reduce our focus on current operations, which in turn, could negatively impact our future results of operations.

We may fail to fully identify problems with any properties we acquire, and as such, assets we acquire may prove to be worth less than we paid because of uncertainties in evaluating recoverable reserves and potential liabilities. We are actively seeking to acquire additional acreage in Texas or other regions in the future. Successful acquisitions require an assessment of a number of factors, including estimates of recoverable reserves, exploration potential, future oil and natural gas prices, adequacy of title, operating and capital costs, and potential environmental and other liabilities. Although we conduct a review that we believe is consistent with industry practices, we can give no assurance that we have identified or will identify all existing or potential problems associated with such properties or that we will be able to mitigate any problems we do identify. Such assessments are inexact and their accuracy is inherently uncertain. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface, title and environmental problems that may exist or arise. We are generally not entitled to contractual indemnification for pre-closing liabilities, including environmental liabilities. Normally, we acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. As a result of these factors, we may not be able to acquire oil and natural gas properties that contain economically recoverable reserves or be able to complete such acquisitions on acceptable terms.

Restrictions on our ability to obtain, recycle and dispose of water may impact our ability to execute our drilling and development plans in a timely or cost-effective manner. Water is an essential component of both the drilling and hydraulic fracturing processes. Historically, we have been able to secure water from local land owners and other third party sources for use in our operations. If drought conditions were to occur or demand for water were to outpace supply, our ability to obtain water could be impacted and in turn, our ability to perform hydraulic fracturing operations could be restricted or made more costly. Along with the risks of other extreme

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weather events, drought risk, in particular, is likely increased by climate change. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows. In addition, significant amounts of water are produced in our operations. Inadequate access to or availability of water recycling or water disposal facilities could adversely affect our production volumes or significantly increase the cost of our operations.

Factors beyond our control, including the availability and capacity of gas processing facilities and pipelines and other transportation operations owned and operated by third parties, affect the marketability of our production. The ability to market oil and natural gas from our wells depends upon numerous factors beyond our control. A significant factor in our ability to market our production is the availability and capacity of gas processing facilities and pipeline and other transportation operations, including trucking services, owned and operated by third parties. These facilities and services may be temporarily unavailable to us due to market conditions, physical or mechanical disruption, weather, lack of contracted capacity, pipeline safety issues, or other reasons. In addition, in certain newer development areas, processing and transportation facilities and services may not be sufficient to accommodate potential production and it may be necessary for new interstate and intrastate pipelines and gathering systems to be built. Our failure to obtain access to processing and transportation facilities and services on acceptable terms could materially harm our business. We may be required to shut in wells for lack of a market or because of inadequate or unavailable processing or transportation capacity. If that were to occur, we would be unable to realize revenue from those wells until transportation arrangements were made to deliver our production to market. Furthermore, if we were required to shut in wells, we might also be obligated to pay shut-in royalties to certain mineral interest owners in order to maintain our leases. If we were required to shut in our production for long periods of time due to lack of transportation capacity, it would have a material adverse effect on our business, financial condition, results of operations and cash flows.

Other factors that affect our ability to market our production include:

• the extent of domestic production and imports/exports of oil and natural gas;

• federal regulations authorizing exports of liquefied natural gas (“LNG”), the development of new LNG export facilities under construction in the U.S. Gulf Coast region, and the first LNG exports from such facilities;

• the construction of new pipelines capable of exporting U.S. natural gas to Mexico and transporting Eagle Ford Shale and Permian Basin oil production to the Gulf Coast;

• the proximity of hydrocarbon production to pipelines;

• the demand for oil and natural gas by utilities and other end users;

• the availability of alternative fuel sources;

• the effects of inclement weather; and

• state and federal regulation of oil, natural gas and NGL marketing and transportation.

We have entered into firm transportation contracts that require us to pay fixed sums of money regardless of quantities actually shipped. If we are unable to deliver the minimum quantities of production, such requirements could adversely affect our results of operations, financial position, and liquidity. We have entered into firm transportation agreements for a portion of our production in certain areas in order to improve our ability, and that of our purchasers, to successfully market our production. We may also enter into firm transportation arrangements for additional production in the future. These firm transportation agreements may be more costly than interruptible or short-term transportation agreements. Additionally, these agreements obligate us to pay fees on minimum volumes regardless of actual throughput. If we have insufficient production to meet the minimum volumes, the requirements to pay for quantities not delivered could have an impact on our results of operations, financial position, and liquidity.

Our estimated reserves are based on interpretations and assumptions that may be inaccurate. Any material inaccuracies in these reserve estimates or underlying assumptions will materially affect the quantities and present value of our reserves. This Annual Report contains estimates of our proved oil and natural gas reserves and the estimated future net cash flows from such reserves. The process of estimating oil and natural gas reserves is complex and requires significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir and is therefore inherently imprecise. These assumptions include those required by the SEC relating to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds.

Actual future production, oil and natural gas prices, revenues, taxes, development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves most likely will vary from the estimates. Any significant variance could materially affect the estimated quantities and present value of reserves shown in this 2019 Annual Report on Form 10-K. Additionally, estimates of reserves and future cash flows may be subject to material downward or upward revisions, based on production history, development drilling and exploration activities and prices of oil and natural gas.

You should not assume that any PV-10 of our estimated proved reserves contained in this 2019 Annual Report on Form 10-K represents the market value of our oil and natural gas reserves. We base the PV-10 from our estimated proved reserves at December 31, 2019 on the 12-Month Average Realized Price and costs as of the date of the estimate. Actual future prices and costs may be materially higher or lower. Further, actual future net revenues will be affected by factors such as the amount and timing of actual development expenditures, the rate and timing of production, and changes in governmental regulations or taxes. Recovery of PUDs generally requires significant

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capital expenditures and successful drilling operations. Our reserve estimates include the assumption that we will make significant capital expenditures to develop these PUDs and the actual costs, development schedule, and results associated with these properties may not be as estimated. In addition, the discount factor used to calculate PV-10 may not be appropriate based on our cost of capital from time to time and the risks associated with our business and the oil and gas industry.

Unless we replace our oil and gas reserves, our reserves and production will decline. Our future oil and gas production depends on our success in finding or acquiring additional reserves. If we fail to replace reserves through drilling or acquisitions, our production, revenues, reserve quantities and cash flows will decline. In general, production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. We may not be successful in finding, developing or acquiring additional reserves, and our efforts may not be economic. Our ability to make the necessary capital investment to maintain or expand our asset base of oil and gas reserves would be limited to the extent cash flow from operations is reduced and external sources of capital become limited or unavailable.

Our identified drilling locations are scheduled to be drilled over many years, making them susceptible to uncertainties that could prevent them from being drilled or delay their drilling. Our management team has identified drilling locations as an estimation of our future development activities on our existing acreage. These identified drilling locations represent a significant part of our growth strategy. Our ability to drill and develop these identified drilling locations depends on a number of uncertainties, including oil and natural gas prices, the availability and cost of capital, availability and cost of drilling, completion and production services and equipment, lease expirations, regulatory approvals, and other factors discussed in these risk factors. Because of these uncertain factors, we do not know if the identified drilling locations will ever be drilled or if we will be able to produce oil or natural gas from these drilling locations. In addition, unless production is established within the spacing units covering the undeveloped acres on which some of the identified locations are located, the leases for such acreage will expire. Therefore, our actual drilling activities may materially differ from those presently identified.

Our exploration and development drilling efforts and the operation of our wells may not be profitable or achieve our targeted returns. Exploration, development, drilling and production activities are subject to many risks. We may invest in property, including undeveloped leasehold acreage, which we believe will result in projects that will add value over time. However, we cannot guarantee that any leasehold acreage acquired will be profitably developed, that new wells drilled will be productive or that we will recover all or any portion of our investment in such leasehold acreage or wells. Drilling for oil and natural gas may involve unprofitable efforts, including wells that are productive but do not produce sufficient net reserves to return a profit after deducting operating and other costs. In addition, we may not be successful in controlling our drilling and production costs to improve our overall return and wells that are profitable may not achieve our targeted rate of return. Wells may have production decline rates that are greater than anticipated. Future drilling and completion efforts may impact production from existing wells, and parent-child effects may impact future well productivity as a result of timing, spacing proximity or other factors. Failure to conduct our oil and gas operations in a profitable manner may result in write-downs of our proved reserves quantities, impairment of our oil and gas properties, and a write-down in the carrying value of our unproved properties, and over time may adversely affect our growth, revenues and cash flows.

The development of our PUDs may take longer and may require higher levels of capital expenditures than we currently anticipate. Developing PUDs requires significant capital expenditures, successful drilling operations, and a substantial amount of our proved reserves are PUDs which may not be ultimately developed or produced. Approximately 57% of our total estimated proved reserves as of December 31, 2019, were PUDs. The reserve data included in the reserve reports of our independent petroleum engineers assume significant capital expenditures will be made to develop such reserves. We cannot be certain that the estimated capital expenditures to develop these reserves are accurate, that development will occur as scheduled, or that the results of such development will be as estimated. We may be forced to limit, delay or cancel drilling operations as a result of a variety of factors, including: unexpected drilling conditions; pressure or irregularities in formations; lack of proximity to and shortage of capacity of transportation facilities; equipment failures or accidents and shortages or delays in the availability of drilling rigs, equipment, personnel and services; and compliance with governmental requirements. Delays in the development of our reserves, increases in costs to drill and develop such reserves or decreases in commodity prices will reduce the future net revenues of our estimated PUDs and may result in some projects becoming uneconomical. In addition, delays in the development of reserves could force us to reclassify certain of our proved reserves as unproved reserves.

The results of our planned development programs in new or emerging 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 Basin are generally more uncertain than drilling results in areas that are more developed and have more established production from horizontal formations. Because emerging areas and associated target formations have limited or no production history, we are less able to rely on past drilling results in those areas as a basis to predict our future drilling results. In addition, horizontal wells drilled in shale formations, as distinguished from vertical wells, utilize multilateral wells and stacked laterals, all of which are subject to well spacing, density and proration requirements of the Texas Railroad Commission (the “RRC”), which requirements could adversely impact our ability to maximize the efficiency of our horizontal wells related to reservoir drainage over time. Further, access to adequate gathering systems or pipeline takeaway capacity and the availability of drilling rigs and other services may be more challenging in new or emerging areas. If our drilling results in these areas are less than anticipated or we are unable to execute our drilling program in these areas because of capital constraints, access to

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gathering systems and takeaway capacity or otherwise, or natural gas and oil prices decline, our investment in these areas may not be as economic as we anticipate, we could incur material write-downs of unevaluated properties and the value of our undeveloped acreage could decline in the future.

Our operations are subject to operating hazards that may adversely impact our ability to conduct business, and we may not be fully insured against all such operating risks. The operating hazards in exploring for and producing oil and natural gas include: encountering unexpected subsurface conditions that cause damage to equipment or personal injury, including loss of life; equipment failures that curtail or stop production or cause severe damage to or destruction of property, natural resources or other equipment; blowouts or other damages to the productive formations of our reserves that require a well to be re-drilled or other corrective action to be taken; and storms and other extreme weather conditions that cause damages to our production facilities or wells. Because of these or other events, we could experience environmental hazards, including release of oil and natural gas from spills, natural gas leaks, accidental leakage of toxic or hazardous materials, such as petroleum liquids, drilling fluids or fracturing fluids, including chemical additives, underground migration, and ruptures. If we experience any of these problems, we could incur substantial losses in excess of our insurance coverage.

The occurrence of a significant event or claim, not fully insured or indemnified against, could have a material adverse effect on our financial condition and operations. In accordance with industry practice, we maintain insurance against some, but not all, of the operating risks to which our business is exposed. Also, no assurance can be given that we will be able to maintain insurance in the future at rates we consider reasonable to cover our possible losses from operating hazards and we may elect no or minimal insurance coverage.

Multi-well pad drilling may result in volatility in our operating results. We utilize multi-well pad drilling where practical. Because wells drilled on a pad are not brought into production until all wells on the pad are drilled and completed and the drilling rig is moved from the location, multi-well pad drilling delays the commencement of production. In addition, problems affecting a single well could adversely affect production from all of the wells on the pad, which would further cause delays in the scheduled commencement of production or interruptions in ongoing production. These delays or interruptions may cause volatility in our operating results. Further, any delay, reduction or curtailment of our development and producing operations due to operational delays caused by multi-well pad drilling could result in the loss of acreage through lease expirations.

The loss of key personnel could adversely affect our ability to operate. We depend, and will continue to depend in the foreseeable future, on the services of our senior officers and other key employees, as well as other third-party consultants with extensive experience and expertise in evaluating and analyzing drilling prospects and producing oil and natural gas and maximizing production from oil and natural gas properties. Our ability to retain our senior officers, other key employees, and third party consultants, many of whom are not subject to employment agreements, is important to our future success and growth. The unexpected loss of the services of one or more of these individuals could have a detrimental effect on our business.

We may not be able to keep pace with technological developments in our industry. The oil and natural gas industry is characterized by rapid and significant technological advancements and introductions of new products and services using new technologies. As others use or develop new technologies, we may be placed at a competitive disadvantage or may be forced by competitive pressures to implement those new technologies at substantial costs. We may not be able to respond to these competitive pressures or implement new technologies on a timely basis or at an acceptable cost. If one or more of the technologies we use now or in the future were to become obsolete, our business, financial condition or results of operations could be materially and adversely affected.

Our business could be negatively affected by security threats. A cyberattack or similar incident could occur and result in information theft, data corruption, operational disruption, damage to our reputation or financial loss.  The oil and natural gas industry has become increasingly dependent on digital technologies to conduct certain exploration, development, production, processing and financial activities. We depend on digital technology to estimate quantities of oil and gas reserves, manage operations, process and record financial and operating data, analyze seismic and drilling information, and communicate with our employees and third party partners. Our technologies, systems, networks, seismic data, reserves information or other proprietary information, and those of our vendors, suppliers and other business partners, may become the target of cyberattacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or could otherwise lead to the disruption of our business operations or other operational disruptions in our exploration or production operations. Cyberattacks are becoming more sophisticated and certain cyber incidents, such as surveillance, may remain undetected for an extended period and could lead to disruptions in critical systems or the unauthorized release of confidential or otherwise protected information. These events could lead to financial losses from remedial actions, loss of business, disruption of operations, damage to our reputation or potential liability. Also, computers control nearly all of the oil and gas distribution systems in the United States and abroad, which are necessary to transport our production to market. A cyberattack directed at oil and gas distribution systems could damage critical distribution and storage assets or the environment, delay or prevent delivery of production to markets and make it difficult or impossible to accurately account for production and settle transactions. Cyber incidents have increased, and the U.S. government has issued warnings indicating that energy assets may be specific targets of cybersecurity threats. Our systems and insurance coverage for protecting against cybersecurity risks may not be sufficient. Further, as cyberattacks continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any vulnerability to cyberattacks.

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We face various risks associated with increased activism against oil and natural gas exploration and development activities. Opposition toward oil and natural gas drilling and development activity has been growing globally and is particularly pronounced in the United States. Companies in the oil and natural gas industry are often the target of activist efforts from both individuals and non-governmental organizations regarding safety, human rights, environmental matters, sustainability, and business practices. Anti-development activists are working to, among other things, reduce access to federal and state government lands and delay or cancel certain operations such as drilling and development.

Risks Related to Financial Position

Our business requires significant capital expenditures and we may not be able to obtain needed capital or financing on satisfactory terms or at all. We make and expect to continue to make substantial capital expenditures in our business for the development, exploitation, production and acquisition of oil and natural gas reserves. Historically, we have funded our capital expenditures through a combination of cash flows from operations, borrowings from financial institutions, the sale of public debt and equity securities and asset dispositions. The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, participation of non-operating working interest owners, the cost and availability of drilling rigs and other services and equipment, and regulatory, technological and competitive developments.

If the borrowing base under our Credit Facility or our revenues decrease, we may have limited ability to obtain the capital necessary to sustain our operations at current levels. The failure to obtain additional financing on terms acceptable to us, or at all, could result in a curtailment of our development activities and could adversely affect our business, financial condition and results of operations.

Our leverage and debt service obligations may adversely affect our financial condition, results of operations and business prospects. As of December 31, 2019, we had aggregate outstanding indebtedness of approximately $3.2 billion. As a result of the Carrizo Acquisition, our level of indebtedness has significantly increased. Our amount of indebtedness could affect our operations in many ways, including:

• requiring us to dedicate a substantial portion of our cash flow from operations to service our existing debt, thereby reducing the cash available to finance our operations and other business activities;

• limiting management’s discretion in operating our business and our flexibility in planning for, or reacting to, changes in our business and the industry in which we operate;

• increasing our vulnerability to downturns and adverse developments in our business and the economy;

• limiting our ability to access the capital markets to raise capital on favorable terms or to obtain additional financing for working capital, capital expenditures or acquisitions or to refinance existing indebtedness;

• making it more likely that a reduction in our borrowing base following a periodic redetermination could require us to repay a portion of our then-outstanding bank borrowings;

• making us vulnerable to increases in interest rates as our indebtedness under our Credit Facility may vary with prevailing interest rates;

• placing us at a competitive disadvantage relative to competitors with lower levels of indebtedness or less restrictive terms governing their indebtedness; and

• making it more difficult for us to satisfy our obligations under our senior notes or other debt and increasing the risk that we may default on our debt obligations.

Restrictive covenants in the agreements governing our indebtedness may limit our ability to respond to changes in market conditions or pursue business opportunities. Our Credit Facility and the indentures governing our senior notes contain restrictive covenants that limit our ability to, among other things: incur additional indebtedness; make investments; merge or consolidate with another entity; pay dividends or make certain other payments; hedge future production or interest rates; create liens that secure indebtedness; sell assets; or engage in certain other transactions without the prior consent of the lenders. As a result of these covenants, we are limited in the manner in which we conduct our business and we may be unable to react to changes in market conditions, take advantage of business opportunities we believe to be desirable, obtain future financing, fund needed capital expenditures or withstand a continuing or future downturn in our business.

In addition, our Credit Facility requires us to maintain certain financial ratios and to make certain required payments of principal, premium, if any, and interest. If we fail to comply with these provisions or other financial and operating covenants in the Credit Facility or the indentures governing our senior notes, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default, the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest, the lenders under our Credit Facility could elect to terminate their commitments thereunder, cease making further loans and institute foreclosure proceedings against our assets; and we could be forced into bankruptcy or liquidation.

Our borrowings under our Credit Facility expose us to interest rate risk. Our earnings are exposed to interest rate risk associated with borrowings under our Credit Facility, which bear interest at a rate elected by us that is based on the prime, LIBOR or federal funds rate plus margins ranging from 0.25% to 2.25% depending on the interest rate used and the amount of the loan outstanding in relation to the borrowing base.

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The borrowing base under our Credit Facility may be reduced below the amount of borrowings outstanding thereunder. The borrowing base under our Credit Facility is currently $2.5 billion, with an elected commitment amount of $2.0 billion, and as of December 31, 2019, we had an aggregate principal balance of $1.3 billion outstanding thereunder. Our borrowing base is subject to redeterminations semi-annually, and a future decrease in borrowing base due to the issuance of new indebtedness, the outcome of a subsequent borrowing base redetermination or an unwillingness or inability on the part of lending counterparties to meet their funding obligations may cause us to not be able to access adequate funding under the Credit Facility. If our borrowing base were to be reduced, we may be unable to implement our drilling and development plan, make acquisitions or otherwise carry out business plans, which would have a material adverse effect on our financial condition and results of operations and impair our ability to service our indebtedness. In addition, we cannot borrow amounts above the elected commitments, even if the borrowing base is greater, without new commitments being obtained from the lenders for such incremental amounts above the elected commitments. In the event the amount outstanding under our Credit Facility exceeds the elected commitments, we must repay such amounts immediately in cash. In the event the amount outstanding under our Credit Facility exceeds the redetermined borrowing base, we are required to either (i) grant liens on additional oil and gas properties (not previously evaluated in determining such borrowing base) with a value equal to or greater than such excess, (ii) repay such excess borrowings over six monthly installments, or (iii) elect a combination of options in clauses (i) and (ii). We may not have sufficient funds to make any required repayment.  If we do not have sufficient funds and are otherwise unable to negotiate renewals of our borrowings or arrange new financing, an event of default would occur under our Credit Facility.

We may not be able to generate sufficient cash to service all of our indebtedness and may be forced to take other actions to satisfy our obligations under applicable debt instruments, which may not be successful. Our ability to make scheduled payments on or to refinance our indebtedness obligations depends on our financial condition and operating performance, which are subject to certain financial, economic, competitive and other factors beyond our control. We may not be able to maintain a level of cash flows from operating activities sufficient to permit us to pay the principal, premium, if any, and interest on our indebtedness.

If our cash flows and capital resources are insufficient to fund debt service obligations, we may be forced to reduce or delay investments and capital expenditures, sell assets, seek additional capital or restructure or refinance indebtedness. These alternative measures may not be successful and may not permit us to meet scheduled debt service obligations. Our ability to restructure or refinance indebtedness will depend on the condition of the capital markets and our financial condition at such time. Also, we may not be able to consummate dispositions at such time on terms acceptable to us or at all, and the proceeds of any such dispositions may not be adequate to meet such debt service obligations. Furthermore, any refinancing of indebtedness could be at higher interest rates and may require us to comply with more onerous covenants, which could further restrict business operations. In addition, the terms of existing or future debt instruments may restrict us from adopting some of these alternatives. For example, our Credit Facility currently restricts our ability to dispose of assets and our use of the proceeds from such disposition.

Any failure to make payments of interest and principal on outstanding indebtedness on a timely basis would likely result in a reduction of our credit rating, which could harm our ability to incur additional indebtedness.

We cannot be certain that we will be able to maintain or improve our leverage position. An element of our business strategy involves maintaining a disciplined approach to financial management. However, we are also seeking to acquire, exploit and develop additional reserves that may require the incurrence of additional indebtedness. Although we will seek to maintain or improve our leverage position, our ability to maintain or reduce our level of indebtedness depends on a variety of factors, including future performance and our future debt financing needs. General economic conditions, oil and natural gas prices and financial, business and other factors will also affect our ability to maintain or improve our leverage position. Many of these factors are beyond our control.

Our hedging program may limit potential gains from increases in commodity prices, result in losses, or be inadequate to protect us against continuing and prolonged declines in commodity prices. We enter into arrangements to hedge a portion of our production from time to time to reduce our exposure to fluctuations in oil and natural gas prices and to achieve more predictable cash flow. Our hedges at December 31, 2019 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 and natural gas. We cannot be certain that the hedging transactions we have entered into, or will enter into, will adequately protect us from continuing and prolonged declines in oil and natural gas prices. To the extent that oil and natural gas prices remain at current levels or decline further, we would not be able to hedge future production at the same pricing level as our current hedges and our results of operations and financial condition may be negatively impacted. 

In addition, in a typical hedge transaction, we will have the right to receive from the other parties to the hedge the excess of the fixed price specified in the hedge over a floating price based on a market index, multiplied by the quantity hedged. If the floating price exceeds the fixed price, we are required to pay the other parties this difference multiplied by the quantity hedged regardless of whether we have sufficient production to cover the quantities specified in the hedge. Significant reductions in production at times when the floating price exceeds the fixed price could require us to make payments under the hedge agreements even though such payments are not offset by sales of physical production.

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Our hedging transactions expose us to counterparty credit risk. Our hedging transactions expose us to risk of financial loss if a counterparty fails to perform under a derivative contract, particularly during periods of falling commodity prices. Disruptions in the financial markets or other factors outside our control could lead to sudden decreases in a counterparty’s liquidity, which could make them unable to perform under the terms of the derivative contract. We are unable to predict sudden changes in a counterparty’s creditworthiness or ability to perform, and even if we do accurately predict sudden changes, our ability to negate the risk may be limited depending on market conditions at the time. If the creditworthiness of any of our counterparties deteriorates and results in their nonperformance, we could incur a significant loss.

The inability of one or more of our customers to meet their obligations to us may adversely affect our financial results.  Our principal exposure to credit risk is through receivables resulting from the sale of our oil and natural gas production, advances to joint interest parties and joint interest receivables. We are also subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. The largest purchaser of our oil and natural gas accounted for approximately 26% of our total revenues for the year ended December 31, 2019. The inability or failure of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results.

Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited. A portion of our NOL carryforward balance was generated prior to the effective date of new limitations on utilization of NOLs imposed by the Tax Cuts and Jobs Act of 2017 (the “Tax Act”) and are allowable as a deduction against 100 percent of taxable income in future years but will start to expire in the tax year 2035. The remainder was generated following such effective date and thus are allowable as a deduction against 80 percent of taxable income in future years and do not expire. Utilization of any NOL carryforwards depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes, upon the occurrence of an ownership change (discussed below), an annual limitation on the amount of our pre-ownership change NOLs we can utilize to offset our taxable income in any taxable year (or portion thereof) ending after such ownership change. The limitation is generally equal to the value of our stock immediately prior to the ownership change multiplied by the long-term tax exempt rate. In general, an ownership change occurs if there is a cumulative increase in our ownership of more than 50 percentage points by one or more “5% shareholders” (as defined in the Internal Revenue Code of 1986, as amended) at any time during a rolling three-year period. The Company has reduced the total recorded NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilizable before they expire. Future ownership changes or future regulatory changes could further limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

Unanticipated changes in effective tax rates or adverse outcomes resulting from examination of our income or other tax returns could adversely affect our financial condition and results of operations.

We are subject to income taxes in the U. S., and our domestic tax assets and liabilities are subject to the allocation of expenses in differing jurisdictions. Our future effective tax rates could be subject to volatility or adversely affected by a number of factors, including:

• changes in the valuation of our deferred tax assets and liabilities;

• expected timing and amount of the release of any tax valuation allowances;

• tax effects of stock-based compensation;

• costs related to intercompany restructurings;

• changes in tax laws, regulations or interpretations thereof; or

• lower than anticipated future earnings in our taxing jurisdictions.

In addition, we may be subject to audits of our income, sales and other transaction taxes by U.S. federal and state authorities. Outcomes from these audits could have an adverse effect on our financial condition and results of operations.

Adverse changes in our credit rating may affect our borrowing capacity and borrowing terms. Our outstanding debt is periodically rated by nationally recognized credit rating agencies. The credit ratings are based on our operating performance, liquidity and leverage ratios, overall financial position, and other factors viewed by the credit rating agencies as relevant to our industry and the economic outlook. Our credit rating may affect the amount of capital we can access, as well as the terms of any financing we may obtain. Because we rely in part on debt financing to fund growth, adverse changes in our credit rating may have a negative effect on our future growth.

A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital. Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth funds, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas production and related infrastructure projects. Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.

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Legal and Regulatory Risks

We are subject to stringent and complex federal, state and local laws and regulations which require compliance that could result in substantial costs, delays or penalties. Our oil and natural gas operations are subject to various federal, state and local governmental regulations that may be changed from time to time in response to economic and political conditions. For a discussion of the material regulations applicable to us, see “Business and Properties—Regulations.”  These laws and regulations may:

• require that we acquire permits before commencing drilling;

• regulate the spacing of wells and unitization and pooling of properties;

• impose limitations on production or operational, emissions control and other conditions on our activities;

• restrict the substances that can be released into the environment or used in connection with drilling and production activities or restrict the disposal of waste from our operations;

• limit or prohibit drilling activities on protected areas, such as wetlands and wilderness;

• impose penalties or other sanctions for accidental or unpermitted spills or releases from our operations; or

• require measures to remediate or mitigate pollution and environmental impacts from current and former operations, such as cleaning up spills or dismantling abandoned 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 control, permitting, or waste handling, storage, transport, remediation or disposal for the oil and natural gas industry and could have a significant impact on our operating costs. In general, the oil and natural gas industry recently has been the subject of increased legislative and regulatory attention with respect to public health and environmental matters. Even if regulatory burdens temporarily ease, the historic trend of more expansive and stricter environmental legislation and regulations may continue in the long-term.  

Further, under these laws and regulations, we could be liable for costs of investigation, removal and remediation, damages to and loss of use of natural resources, loss of profits or impairment of earning capacity, property damages, costs of increased public services, as well as administrative, civil and criminal fines and penalties, and injunctive relief. Certain environmental statutes, including the RCRA, CERCLA, OPA and analogous state laws and regulations, impose strict, joint and several liability for costs required to investigate, clean up and restore sites where hazardous substances or other waste products have been disposed of or otherwise released (i.e., liability may be imposed regardless of whether the current owner or operator was responsible for the release or contamination or whether the operations were in compliance with all applicable laws at the time the release or contamination occurred). We could also be affected by more stringent laws and regulations adopted in the future, including any related to climate change, engine and other equipment emissions, GHGs and hydraulic fracturing. Under common law, we could be liable for injuries to people and property. We maintain limited insurance coverage for sudden and accidental environmental damages. We do not believe that insurance coverage for environmental damages that occur over time is available at a reasonable cost. Also, we do not believe that insurance coverage for the full potential liability that could be caused by sudden and accidental environmental damages is available at a reasonable cost. Accordingly, we may be subject to liability in excess of our insurance coverage or we may be required to curtail or cease production from properties in the event of environmental incidents.

Federal legislation and state and local legislative and regulatory initiatives relating to hydraulic fracturing and water disposal wells could result in increased costs and additional operating restrictions or delays. Hydraulic fracturing is used to stimulate production of hydrocarbons from tight formations. The process involves the injection of water, sand and chemicals under pressure into formations to fracture the surrounding rock and stimulate production and is typically regulated by state oil and gas commissions. However, from time to time, the U.S. Congress has considered adopting legislation intended to provide for federal regulation of hydraulic fracturing. Legislation has been proposed in recent sessions of Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection” and to require federal permitting and regulatory control of hydraulic fracturing but has not passed. Furthermore, several federal agencies have asserted regulatory authority over certain aspects of the process. For example, in February 2014, the EPA published permitting guidance addressing the use of diesel fuel in hydraulic fracturing operations, and issued an interpretive memorandum clarifying that hydraulic fracturing with fluids containing diesel fuel is subject to regulation under the Underground Injection Control program, specifically as “Class II” Underground Injection Control wells under the Safe Drinking Water Act. The EPA has also published air emission standards for certain equipment, processes and activities across the oil and natural gas sector, although the EPA proposed amendments in August 2019 that would rescind requirements related to the regulation of methane emissions. Additionally, the BLM published a final rule in March 2015 containing disclosure requirements and other mandates for hydraulic fracturing on federal and Indian lands. Although the BLM subsequently rescinded the rule in December 2017, the rescission has been challenged in federal court by several environmental groups and states. In November 2016, the BLM also issued rules to limit methane emissions from new and existing oil and gas operations on federal lands, but subsequently relaxed and rescinded certain requirements of the rules in September 2018; a lawsuit challenging the September 2018 rule revision is pending.

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In some areas of Texas, including the Eagle Ford Shale and Permian Basin, there has been concern that certain formations into which disposal wells are injecting produced waters could become over-pressured after many years of injection, and the RRC is reviewing the data to determine whether any regulatory action is necessary to address this issue. If the RRC were to decline to issue permits for, or limit the volumes of, new injection wells into the formations that we currently utilize, we may be required to seek alternative methods of disposing of produced waters, including injecting into deeper formations, which could increase our costs.

Some states have adopted, and other states are considering adopting, regulations that could restrict hydraulic fracturing in certain circumstances, impose additional requirements on hydraulic fracturing activities or otherwise require the public disclosure of chemicals used in the hydraulic fracturing process. For example, Texas law requires the chemical components used in the hydraulic fracturing process, as well as the volume of water used, must be disclosed to the RRC and the public. Furthermore, the RRC issued the “well integrity rule” in May 2013, which includes testing and reporting requirements, such as (i) the requirement to submit to the RRC cementing reports after well completion or cessation of drilling, and (ii) the imposition of additional testing on wells less than 1,000 feet below usable groundwater. Additionally, in October 2014, the RRC adopted a rule requiring 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 clarifies the RRC’s 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 waste disposal wells. In addition to state law, local land use restrictions, such as city ordinances, may restrict or prohibit the performance of drilling in general or hydraulic fracturing in particular.

In December 2016, the EPA 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.” This report concludes that hydraulic fracturing can impact drinking water resources in certain circumstances but also noted that certain data gaps and uncertainties limited EPA’s ability to fully characterize the severity of impacts or calculate the national frequency of impacts on drinking water resources from activities in the hydraulic fracturing water cycle. This study could result in additional regulatory scrutiny that could restrict our ability to perform hydraulic fracturing and increase our costs of compliance and doing business.

There has been increasing public controversy regarding hydraulic fracturing with regard to the use of fracturing fluids, induced seismic activity, impacts on drinking water supplies, water usage and the potential for impacts to surface water, groundwater and the environment generally, and a number of lawsuits and enforcement actions have been initiated across the country implicating hydraulic fracturing practices. Several states and municipalities have adopted, or are considering adopting, regulations that could restrict or prohibit hydraulic fracturing in certain circumstances. If new laws or regulations that significantly restrict hydraulic fracturing or water disposal wells are adopted, such laws could make it more difficult or costly for us to drill for and produce oil and natural gas as well as make it easier for third parties opposing the hydraulic fracturing process to initiate legal proceedings. In addition, if hydraulic fracturing is further regulated at the federal, state or local level, our fracturing activities could become subject to additional permitting and financial assurance requirements, more stringent construction specifications, increased monitoring, reporting and recordkeeping obligations, plugging and abandonment requirements, permitting delays and potential increases in costs. These changes could cause us to incur substantial compliance costs, and compliance or the consequences of any failure to comply by us could have a material adverse effect on our financial condition and results of operations. At this time, it is not possible to estimate the impact on our business of newly enacted or potential federal, state or local laws governing hydraulic fracturing.

Climate change legislation or regulations restricting emissions of GHG, changes in the availability of financing for fossil fuel companies, and physical effects from climate change could adversely impact our operating costs and demand for the oil and natural gas we produce. In recent years, federal, state and local governments have taken steps to reduce emissions of GHGs. The EPA has finalized a series of GHG monitoring, reporting and emissions control rules, and the U.S. Congress has, from time to time, considered adopting legislation to reduce emissions. Several states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories or regional GHG cap-and-trade programs. While we are subject to certain federal GHG monitoring and reporting requirements, our operations currently are not adversely impacted by existing federal, state and local climate change initiatives. For a description of existing and proposed GHG rules and regulations, see “Regulations.”

In December 2015, the 21st Conference of the Parties of the United Nations Framework Convention on Climate Change resulted in 195 countries, including the United States, coming together to develop the Paris Agreement, which calls for the parties to undertake “ambitious efforts” to limit the average global temperature. The Agreement went into effect on November 4, 2016, and establishes a framework for the parties to cooperate and report actions to reduce GHG emissions. The United States formally announced its intent to withdraw from the Paris Agreement on November 4, 2019, which withdrawal will become effective on November 4, 2020. Certain U.S. city and state governments have announced their intention to satisfy their proportionate obligations under the Paris Agreement. A number of states have begun taking actions to control or reduce emissions of GHGs. Restrictions on GHG emissions that may be imposed could adversely affect the oil and gas industry. The adoption of legislation or regulatory programs to reduce GHG emissions could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or comply with new regulatory requirements. Any GHG emissions legislation or regulatory programs applicable to power plants or refineries could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Moreover, incentives or requirements to conserve energy, use alternative energy sources, reduce GHG emissions in product supply chains, and increase demand for low-carbon

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fuel or zero-emissions vehicles, could reduce demand for the oil and natural gas we produce. Consequently, legislation and regulatory programs to reduce GHG emissions could have an adverse effect on our business, financial condition and results of operations.

In addition, fuel conservation measures, alternative fuel requirements and increasing consumer demand for alternatives to oil and natural gas could reduce demand for oil and natural gas. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could impact our business activities, operations and ability to access capital. Furthermore, some parties have initiated public nuisance claims under federal or state common law against certain companies involved in the production of oil and natural gas. As a result, private individuals or public entities may seek to enforce environmental laws and regulations against us and could allege personal injury, property damages or other liabilities. Although our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could significantly impact our operations and could have an adverse impact on our financial condition.

Finally, most scientists have concluded that increasing concentrations of GHGs in the Earth’s atmosphere may produce significant physical effects, such as increased frequency and severity of droughts, storms, floods and other climatic events. If any such effects were to occur, they could adversely affect or delay demand for the oil or natural gas produced or cause us to incur significant costs in preparing for or responding to the effects of climatic events themselves. Potential adverse effects could include disruption of our production activities, including, for example, damages to our facilities from winds or floods or increases in our costs of operation or reductions in the efficiency of our operations, as well as potentially increased costs for insurance coverages in the aftermath of such effects.

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”) and the SEC to enact further regulations affecting derivative contracts, including the derivative contracts we use to hedge our exposure to price volatility through the over-the-counter market.

Although the CFTC and the SEC have issued final regulations in certain areas, final rules in other areas, including the scope of relevant definitions or exemptions, remain pending. In one of the CFTC’s rulemaking proceedings still pending under the Dodd-Frank Act, the CFTC has proposed but not yet finalized position limits for certain futures and options contracts in various commodities and for swaps that are their economic equivalents (with exemptions for certain bona fide hedging transactions). Similarly, the CFTC has proposed but not yet finalized a rule regarding the capital that a swap dealer or major swap participant is required to post with respect to its swap business. The CFTC issued a final rule on margin requirements for uncleared swap transactions in January 2016, which it amended in November 2018. The final rule as amended includes an exemption for certain commercial end-users that enter into uncleared swaps in order to hedge bona fide commercial risks affecting their business. In addition, the CFTC has issued a final rule authorizing an exception from the requirement to use cleared exchanges (rather than hedging over-the-counter) for commercial end-users who use swaps to hedge their commercial risks. The Dodd-Frank Act also imposes recordkeeping and reporting obligations on counterparties to swap transactions and other regulatory compliance obligations. All of the above regulations could increase the costs to us of entering into financial derivative transactions to hedge or mitigate our exposure to commodity price volatility and other commercial risks affecting our business.

It is not possible at this time to predict the timing or contents of the CFTC’s final rules on position limits or capital requirements. Depending on our ability to satisfy the CFTC’s requirements for the various exemptions available for a commercial end-user using swaps to hedge or mitigate its commercial risks, the final rules may provide beneficial exemptions or may require us to comply with position limits and other limitations with respect to our financial derivative activities. When a final rule on capital requirements is issued, the Dodd-Frank Act may require our current counterparties to post additional capital as a result of entering into uncleared financial derivatives with us, which could increase the cost to us of entering into such derivatives. The Dodd-Frank Act may also require our current counterparties to financial derivative transactions to cease their current business as hedge providers or spin off some of their derivatives activities to separate entities, which may not be as creditworthy as the current counterparties. These potential changes could reduce the liquidity of the financial derivatives markets which would reduce the ability of commercial end-users like us to hedge or mitigate their exposure to commodity price volatility. The Dodd-Frank Act and any new regulations could significantly increase the cost of derivative contracts, materially alter the terms of future swaps relative to the terms of our existing financial derivative contracts, and reduce the availability of derivatives to protect against commercial risks we encounter.

In addition, federal banking regulators have adopted new capital requirements for certain regulated financial institutions in connection with the Basel III Accord. The Federal Reserve Board also issued proposed regulations on September 30, 2016, proposing to impose higher risk-weighted capital requirements on financial institutions active in physical commodities, such as oil and natural gas. If and when these proposed regulations are fully implemented, financial institutions subject to these higher capital requirements may require that we provide cash or other collateral with respect to our obligations under the financial derivatives and other contracts in order to reduce the amount of capital such financial institutions may have to maintain. Alternatively, financial institutions subject to these capital requirements may require premiums to enter into derivatives and other physical commodity transactions to compensate for the additional capital costs for these transactions. Rules implementing the Basel III Accord and higher risk-weighted capital requirements could materially

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reduce our liquidity and increase the cost of derivative contracts and other physical commodity contracts (including through requirements to post collateral which could adversely affect our available capital for other commercial operations purposes).

If we reduce our use of derivative contracts as a result of any of the foregoing new requirements, our results of operations may become more volatile and cash flows less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Our revenues could be adversely affected if a consequence of the legislation and regulations is to lower commodity prices. Any of these consequences could have a material adverse effect on our consolidated financial position, results of operations, or cash flows.

Tax laws and regulations may change over time, and the recently passed comprehensive tax reform bill could adversely affect our business and financial condition. On December 22, 2017, the President signed into law Public Law No. 115-97, a comprehensive tax reform bill commonly referred to as 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 12 - Income Taxes” to our consolidated financial statements included elsewhere in this 2019 Annual Report on Form 10-K for additional information.

In addition, from 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 percentage depletion allowance for oil and natural gas properties and (iii) an extension of the amortization period for certain geological and geophysical expenditures. While these specific changes were not included in the Tax Act, no accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future or, if enacted, what the specific provisions or the effective date of any such legislation would be. 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.

We may be subject to the actions of activist shareholders. We have been the subject of an activist shareholder in the past. Responding to shareholder activism can be costly and time-consuming, disrupt our operations and divert the attention of management and our employees from executing our business plan. Activist campaigns can create perceived uncertainties as to our future direction, strategy or leadership and may result in the loss of potential business opportunities, harm our ability to attract new investors, customers and joint venture partners and cause our stock price to experience periods of volatility or stagnation. Moreover, if individuals are elected to our Board of Directors with a specific agenda, our ability to effectively and timely implement our current initiatives, retain and attract experienced executives and employees and execute on our long-term strategy may be adversely affected.

Risks Related to our Common Stock

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.

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Alternatively, if a court were to find this choice of forum provision inapplicable to, or unenforceable in respect of, one or more of the specified types of actions or proceedings, we may incur additional costs associated with resolving such matters in other jurisdictions, which could adversely affect its business, financial condition, prospects, or results of operations.

Provisions of our charter documents and Delaware law may inhibit a takeover, which could limit the price investors might be willing to pay in the future for our common stock. Provisions in our certificate of incorporation and bylaws may have the effect of delaying or preventing an acquisition of the Company or a merger in which we are not the surviving company and may otherwise prevent or slow changes in our Board of Directors and management. In addition, because we are incorporated in Delaware, we are governed by the provisions of Section 203 of the DGCL. These provisions could discourage an acquisition of the Company or other change in control transactions and thereby negatively affect the price that investors might be willing to pay in the future for our common stock.

We have no current plans to pay cash dividends on our common stock. Our Credit Facility and the indentures governing our senior notes limit our ability to pay dividends and make other distributions. We have no current plans to pay dividends on our common stock and any future determination as to the declaration and payment of cash dividends will be at the discretion of our Board of Directors and will depend upon our financial condition, results of operations, contractual restrictions, capital requirements, business prospects and other factors deemed relevant by our Board of Directors at the time of such determination. Consequently, unless we revise our dividend plans, a shareholder’s only opportunity to achieve a return on its investment in us will be by selling its shares of our common stock at a price greater than the shareholder paid for it. There is no guarantee that the price of our common stock that will prevail in the market will exceed the price at which a shareholder purchased its shares of our common stock.

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 issue securities to raise capital. We may also acquire interests in other companies by using any combination of cash and our common stock or other securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our company, reduce our earnings per share or have an adverse impact on the price of our common stock. In addition, secondary sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. Any such reduction in the market price of our common stock could impair our ability to raise additional capital through the sale of our securities.

ITEM 1B.  Unresolved Staff Comments

None.

ITEM 3.  Legal Proceedings 

We are a defendant in various legal proceedings and claims, which arise in the ordinary course of our business. While the outcome of these events cannot be predicted with certainty, we believe that the ultimate resolution of any such actions will not have a material effect on our financial position or results of operations.

ITEM 4.  Mine Safety Disclosures

Not applicable.

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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 under the symbol “CPE”.

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Holders

As of February 21, 2020 the Company had approximately 2,597 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 intend to reinvest our cash flows and earnings into our business and pay down debt. The declaration and payment of dividends 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.

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Performance Graph

The following stock price performance graph is intended to allow review of stockholder returns, expressed in terms of the performance of the Company’s common stock relative to a broad-based stock performance index and a peer group of companies. The information is included for historical comparative purposes only and should not be considered indicative of future stock performance.

The 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, 2014 through December 31, 2019. The companies in the peer group include Cimarex Energy Co., Centennial Resource Development, Inc., Magnolia Oil & Gas Corporation, Matador Resources, Inc., Oasis Petroleum, Inc., Parsley Energy, Inc., PDC Energy, Inc., QEP Resources, Inc., SM Energy Company, Whiting Petroleum Corporation, and WPX Energy, Inc.

The stock 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 Securities Exchange Act of 1934, each as amended, except to the extent that the Company specifically incorporates it by reference into such filing

Comparison of Five Year Cumulative Total Return

Assumes Initial Investment of $100

December 31, 2019

	Years Ended December 31,
Company/Market/Peer Group	2014		2015		2016		2017		2018		2019
Callon Petroleum Company		$100		$153		$282		$223		$119		$89
S&P 500 Index - Total Returns	100		101		114		138		132		174
Peer Group	100		74		125		98		67		56

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ITEM 6.  Selected Financial Data

The following table sets forth, as of the dates and for the periods indicated, selected financial information about the Company. The financial information for each of the five years in the period ended December 31, 2019 has been derived from our audited Consolidated Financial Statements for such periods. The information should be read in conjunction with “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the Consolidated Financial Statements and Notes thereto. The following information is not necessarily indicative of our future results.

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	Years Ended December 31,
	2019			2018			2017			2016			2015
Statement of Operations Data (1)	(In thousands, except per share amounts)
Oil, natural gas, and NGL revenue		$671,572			$587,624			$366,474			$200,851			$137,512
Total operating expenses	498,914			328,094			225,028			248,328			346,622
Income (loss) from operations	172,658			259,530			141,446			(47,477		)	(209,110		)
Income (loss) available to common stockholders (2)	67,928			300,360			120,424			(99,108		)	(248,034		)
Income (loss) available to common stockholders per common share:
Basic		$0.24			$1.35			$0.56			($0.78	)		($3.77	)
Diluted		$0.24			$1.35			$0.56			($0.78	)		($3.77	)
Weighted average common shares outstanding:
Basic	233,140			216,941			201,526			126,258			65,708
Diluted	233,550			217,596			202,102			126,258			65,708
Statement of Cash Flows Data
Net cash provided by operating activities		$476,316			$467,654			$229,891			$120,774			$89,319
Net cash used in investing activities	(388,389		)	(1,324,057		)	(1,072,532		)	(866,287		)	(259,160		)
Net cash provided by (used in) financing activities	(90,637		)	844,459			217,643			1,397,282			170,097
Balance Sheet Data
Total oil and natural gas properties		$6,669,118			$3,718,858			$2,513,491			$1,475,401			$711,386
Total assets	7,194,838			3,979,173			2,693,296			2,267,587			788,594
Long-term debt (3)	3,186,109			1,189,473			620,196			390,219			328,565
Stockholders’ equity	3,223,308			2,445,208			1,855,966			1,733,402			362,758
Proved Reserves Data (4)
Oil (MBbls)	346,361			180,097			107,072			71,145			43,348
Natural gas (MMcf)	757,134			350,466			179,410			122,611			65,537
NGLs (MBbls)	67,462			—			—			—			—
Total proved reserves (MBoe)	540,012			238,508			136,974			91,580			54,271
Standardized measure of discounted future net cash flows		$4,951,026			$2,941,293			$1,556,682			$809,832			$570,890

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

(2) Net loss for 2015 included the recognition of a write-down of oil and natural gas properties of $208.4 million as a result of the ceiling test limitation and $108.8 million of income tax expense related to the recognition of a valuation allowance. Net loss for 2016 included the recognition of a write-down of oil and natural gas properties of $95.8 million as a result of the ceiling test limitation.

(3) See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

(4) The estimated proved reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other estimated proved reserve volumes are on a two-stream basis.

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ITEM 7.  Management’s Discussion and Analysis of Financial Condition and Results of Operations

A discussion and analysis of the Company’s financial condition and results of operations for the year ended December 31, 2017 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, 2018, which was filed with the SEC on February 27, 2019 and is incorporated herein by reference.

General

The following discussion and analysis of our financial condition and results of operations should be read in conjunction with the accompanying audited consolidated financial statements, information about our business practices, significant accounting policies, risk factors, and the transactions that underlie our financial results, which are included in various parts of this filing.

Our website address is www.callon.com. All of our filings 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 2019 Annual Report on Form 10-K.

We are an independent oil and natural gas company incorporated in the State of Delaware in 1994, but our roots go back nearly 70 years to our Company’s establishment in 1950. We are focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. Our activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basis in West Texas. In 2019, though our acquisition of Carrizo, we doubled our core acreage position in the Delaware Basin and entered the Eagle Ford Shale.  

Our operating culture is centered on responsible development of hydrocarbon resources, safety and the environment, which we believe strengthens our operational performance. Our drilling activity is predominantly focused on the horizontal development of several prospective intervals in the Permian Basin, including multiple levels of the Wolfcamp formation and the Lower Spraberry shales, and more recently as a result of the Carrizo Acquisition, the Eagle Ford Shale. 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 acquisition of additional locations through working interest acquisitions, leasing programs, acreage purchases, joint ventures and asset swaps.

Overview

Significant Accomplishments in 2019

• On December 20, 2019, we completed the Carrizo Acquisition which increased our portfolio to: (i) over 116,000 net acres in the Permian Basin, which doubled our footprint in the Southern Delaware Basin and (ii) expanded our portfolio to include over 76,000 net acres in the mature, high-margin, free cash flow generating Eagle Ford Shale.

• In connection with the Carrizo Acquisition, we entered into the Credit Facility, which has a maximum credit amount of $5.0 billion. As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion.

• During 2019, we completed divestitures of non-core assets for aggregate net proceeds of $294.4 million. In addition, we could receive cash for settlements of our contingent consideration arrangement of up to $60.0 million if crude oil prices exceed specified thresholds for each of the years of 2019 through 2021.

• Our total production in 2019 increased by 26% to 15.1 MMBoe (77% oil) as compared to 2018.

• On July 18, 2019, we redeemed all of the outstanding Preferred Stock for $73.0 million.

• For the year ended December 31, 2019, we drilled 63 gross (55.7 net) horizontal wells, completed 55 gross (47.1 net) horizontal wells and had, as of December 31, 2019, 64 gross (57.7 net) horizontal wells awaiting completion.

• Estimated proved reserves as of December 31, 2019 were 540.0 MMBoe (64% oil), with 43% classified as proved developed.

Reserves Growth

As of December 31, 2019, our estimated proved reserves increased 126% to 540.0 MMBoe compared to 238.5 MMBoe of estimated proved reserves at year-end 2018. Our significant growth in proved reserves was primarily attributable to the Carrizo Acquisition, along with our horizontal development efforts. Our estimated proved reserves at year-end 2019 and 2018 were 64% and 76% oil, respectively.

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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:

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	Years Ended December 31,
	2019 (1)			2018			$ Change			% Change
Total production (2)
Oil (MBbls)	11,665			9,443			2,222			24	%
Natural gas (MMcf)	19,718			15,447			4,271			28	%
NGLs (MBbls)	135			—			135			100	%
Total barrels of oil equivalent (MBoe)	15,086			12,018			3,068			26	%
Total daily production (Boe/d)	41,331			32,926			8,405			26	%
Oil as % of total daily production	77		%	79		%
Average realized sales price (excluding impact of settled derivatives)
Oil (per Bbl)		$54.27			$56.22			($1.95	)	(3	%)
Natural gas (per Mcf)	1.85			3.67			(1.82		)	(50	%)
NGLs (per Bbl)	15.37			—			15.37			100	%
Total (per Boe)	44.52			48.90			(4.38		)	(9	%)
Average realized sales price (including impact of settled derivatives)
Oil (per Bbl)		$53.31			$53.31			$—		—	%
Natural gas (per Mcf)	2.22			3.69			(1.47		)	(40	%)
NGLs (per Bbl)	15.37			—			15.37			100	%
Total (per Boe)	44.27			46.63			(2.36		)	(5	%)
Revenues (in thousands)
Oil		$633,107			$530,898			$102,209		19	%
Natural gas	36,390			56,726			(20,336		)	(36	%)
NGLs	2,075			—			2,075			100	%
Total revenues		$671,572			$587,624			$83,948		14	%
Additional per Boe data
Lease operating expense (3)	6.09			5.76			0.33			6	%
Production taxes	2.83			2.98			(0.15		)	(5	%)
Benchmark prices(4)
WTI (per Bbl)		$56.98			$65.23			($8.25	)	(13	%)
Henry Hub (per Mcf)	2.56			3.15			(0.59		)	(19	%)

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

(2) The production associated with reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other reserve volumes are on a two-stream basis.

(3) Excludes gathering and treating expense.

(4) Reflects calendar average daily spot market prices.

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Revenues

The following table is intended to reconcile the change in oil, natural gas, NGLs, and total revenue for the period presented by reflecting the effect of changes in volume and in the underlying commodity prices.

	Oil			Natural Gas			NGLs		Total
	(In thousands)
Revenues for the year ended December 31, 2018		$530,898			$56,726			$—		$587,624
Volume increase (decrease)	124,869			15,683			2,075		142,627
Price increase (decrease)	(22,660		)	(36,019		)	—		(58,679		)
Net increase (decrease)	102,209			(20,336		)	2,075		83,948
Revenues for the year ended December 31, 2019 (1)(2)		$633,107			$36,390			$2,075		$671,572

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

(2) The revenues associated with production from reserves acquired in the Carrizo Acquisition are presented on a three-stream basis and include NGLs, whereas, all other revenue is presented on a two-stream basis.

Commodity Prices

The prices for oil, natural gas, and NGLs remain extremely volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and actions by OPEC and other countries and government actions. Prices of oil, natural gas, and NGLs will affect the following aspects of our business:

• our revenues, cash flows and earnings;

• the amount 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 the Credit Facility; and

• the value of our oil and natural gas properties.

Oil revenue

For the year ended December 31, 2019, oil revenues of $633.1 million increased $102.2 million, or 19%, compared to revenues of $530.9 million for the year ended December 31, 2018. The increase in oil revenue was primarily attributable to a 24% increase in production, partially offset by a 3% decrease in the average realized sales price, which declined to $54.27 per Bbl from $56.22 per Bbl. The increase in production was comprised of 3.2 MMBbls attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells.

Natural gas revenue

Natural gas revenues decreased $20.3 million, or 36%, during the year ended December 31, 2019 to $36.4 million as compared to $56.7 million for the year ended December 31, 2018. The decrease primarily relates to an approximate 50% decrease in the average price realized, which declined to $1.85 per Mcf from $3.67 per Mcf. The decrease was partially offset by a 28% increase in natural gas volumes. The increase in production was comprised of 4.6 Bcf attributable to wells placed on production as a result of our horizontal drilling program, partially offset by normal and expected declines from our existing wells.

NGL revenue

We recognized NGL revenues of $2.1 million as a result of the recent Carrizo Acquisition.

Operating Expenses

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	Years Ended December 31,
			Per				Per		Total Change				Boe Change
	2019		Boe		2018		Boe		$		%		$			%
	(In thousands, except per Boe and % amounts)
Lease operating expenses		$91,827		$6.09		$69,180		$5.76		$22,647	33	%		$0.33		6	%
Production taxes	42,651		2.83		35,755		2.98		6,896		19	%	(0.15		)	(5	%)
Depreciation, depletion and amortization	240,642		15.95		182,783		15.21		57,859		32	%	0.74			5	%
General and administrative	45,331		3.00		35,293		2.94		10,038		28	%	0.06			2	%
Merger and integration expenses	74,363		4.93		—		—		74,363		100	%	4.93			100	%
Settled share-based awards	3,024		0.20		—		—		3,024		100	%	0.20			100	%

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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.

Lease operating expenses for the year ended December 31, 2019 increased by 33% to $91.8 million compared to $69.2 million for the same period of 2018, primarily due to production volumes increasing 26%. Lease operating expense per Boe for the year ended December 31, 2019 increased to $6.09 compared to $5.76 for the same period of 2018 primarily due to increased non-operated activity related to previous acquisitions and workovers.

Production taxes. Production taxes include severance and ad valorem taxes. In general, 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. 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. We benefit from tax credits and exemptions in our various taxing jurisdictions where available.

For the year ended December 31, 2019, production taxes increased 19% to $42.7 million compared to $35.8 million for the same period in 2018, due to an increase in severance taxes based on higher production volumes as well as an increase in ad valorem taxes due to a higher valuation of our oil and gas properties by the taxing jurisdictions and previous acquisitions. On a per Boe basis, production taxes for the year ended December 31, 2019 decreased by 5% compared to the same period of 2018. Also, production taxes as a percentage of total revenues for the year ended December 31, 2019 increased to 6.4% compared to 6.1% for the same period of 2018, due to higher ad valorem taxes as a result of higher valuations of our oil and gas properties during 2019.

Depreciation, depletion and amortization (“DD&A”). Under the full cost accounting method, we capitalize costs within a cost center and then systematically amortize those costs on an equivalent unit-of-production method based on production and estimated proved gas reserve quantities. Depreciation of other property and equipment is computed using the straight line method over their estimated useful lives, which range from three to twenty years.

For the year ended December 31, 2019, DD&A increased 32% to $240.6 million from $182.8 million compared to the same period of 2018. The increase is primarily attributable to a 26% increase in production, as discussed above, and a 5% increase in our DD&A per Boe rate. For the year ended December 31, 2019, DD&A per Boe increased to $15.95 compared to $15.21 for the same period of 2018.

General and administrative, net of amounts capitalized (“G&A”). G&A for the year ended December 31, 2019 increased to $45.3 million compared to $35.3 million for the same period of 2018. G&A for the periods indicated include the following:

	Years Ended December 31,
	2019		2018		$ Change		% Change
	(In thousands, except % amounts)
G&A		$37,174		$28,710		$8,464	29	%
Share-based compensation	7,043		6,224		819		13	%
Fair value adjustments of cash-settled RSU awards	672		359		313		87	%
Fair value adjustments of cash-settled stock appreciation rights	442		—		442		100	%
Total G&A expenses		$45,331		$35,293		$10,038	28	%

Merger and integration expense. For the year ended December 31, 2019, the Company incurred $74.4 million of expenses associated with the Carrizo Acquisition. See “Note 4 – Acquisitions and Divestitures” of the Notes to our Consolidated Financial Statements for additional information regarding the merger with Carrizo.

Settled share-based awards. During the first quarter of 2019, the Company settled certain of the outstanding share-based award agreements of two former officers of the Company, resulting in $3.0 million recorded on the consolidated statements of operations.

Other Income and Expenses

	Years Ended December 31,
	2019			2018			$ Change			% Change
	(In thousands, except % amounts)
Interest expense		$81,399			$58,651			$22,748		39	%
Capitalized interest	(78,492		)	(56,151		)	(22,341		)	40	%
Interest expense, net of capitalized amounts	2,907			2,500			407			16	%
(Gain) loss on derivative contracts		$62,109			($48,544	)		$110,653		(228	%)

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Interest expense, net of capitalized amounts. We finance a portion 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

46

include the amortization of deferred financing costs (including origination and amendment fees), commitment fees and annual agency fees in interest expense.

Interest expense, net of capitalized amounts, incurred during the year ended December 31, 2019 increased $0.4 million to $2.9 million compared to $2.5 million for the same period of 2018.

Loss on extinguishment of debt. During December 2019, in connection with the Carrizo Acquisition, we entered into a new credit facility and simultaneously terminated our prior credit facility. As a result of terminating the prior credit facility, we recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the prior credit facility. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

Gain (loss) on derivative contracts. We utilize commodity derivative financial instruments to reduce our exposure to fluctuations in commodity prices. This amount represents the (i) gain (loss) related to fair value adjustments on our open derivative contracts and (ii) gains (losses) on settlements of derivative contracts for positions that have settled within the period.

For the year ended December 31, 2019, the net loss on derivative contracts was $62.1 million, compared to a $48.5 million net gain in 2018. The net gain (loss) on derivative contracts for the periods indicated includes the following:

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	Years Ended December 31,
	2019			2018			Change
	(In thousands)
Oil derivatives
Net gain (loss) on settlements		($11,188	)		($27,510	)		$16,322
Net gain (loss) on fair value adjustments	(62,125		)	72,973			(135,098		)
Total gain (loss) on oil derivatives		($73,313	)		$45,463			($118,776	)
Natural gas derivatives
Net gain (loss) on settlements		$7,399			$238			$7,161
Net gain (loss) on fair value adjustments	1,490			2,843			(1,353		)
Total gain (loss) on natural gas derivatives		$8,889			$3,081			$5,808
Contingent consideration arrangements
Net gain (loss) on fair value adjustments		$2,315			$—			$2,315
Total gain (loss) on derivative contracts		($62,109	)		$48,544			($110,653	)

See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements for additional information.

Income tax expense. 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 deferred tax assets will not be realized.

The Company recorded income tax expense of $35.3 million for the year ended December 31, 2019 compared to $8.1 million for the same period of 2018. The change in income tax is primarily related to the change in the Company’s tax position in the current period, as the Company no longer maintains a valuation allowance against its deferred tax assets. Current period income tax expense is comprised of both deferred federal and state income tax expense.

Preferred stock dividends.  Holders of our Preferred Stock were 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, 2019 decreased 45% to $4.0 million compared to $7.3 million in 2018. The decrease is attributable to the redemption of our preferred stock in July 2019. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 

Loss on redemption of preferred stock. As a result of the redemption of our Preferred Stock mentioned above, we recognized an $8.3 million loss due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information. 

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Liquidity and Capital Resources

Our primary uses of capital have historically been for the acquisition, development, and exploration of oil and natural gas properties. Our capital program could vary depending upon factors, including, but not limited to, the availability of drilling rigs and completion crews, the cost of completion services, acquisitions and divestitures of oil and gas properties, land and industry partner issues, our available cash flow and financing, success of drilling programs, weather delays, commodity prices, market conditions, the acquisition of leases with drilling commitments and other factors.

Historically, our primary sources of capital have been cash flows from operations, borrowings under our revolving credit facility, proceeds from the issuance of debt securities and public equity offerings, and non-core asset dispositions.  As we pursue reserves and production growth, we regularly consider which resources, including debt and equity financings, are available to meet our future financial obligations, planned capital expenditures and liquidity requirements.

Overview of Cash Flow Activities. For the year ended December 31, 2019, cash and cash equivalents decreased $2.7 million to $13.3 million compared to $16.1 million at December 31, 2018.

	Years Ended December 31,
	2019			2018
	(In thousands)
Net cash provided by operating activities		$476,316			$467,654
Net cash used in investing activities	(388,389		)	(1,324,057		)
Net cash provided by (used in) financing activities	(90,637		)	844,459
Net change in cash and cash equivalents		($2,710	)		($11,944	)

Operating activities. Net cash provided by operating activities was $476.3 million and $467.7 million for the years ended December 31, 2019 and 2018, respectively. The change in operating activities was predominantly attributable to the following:

• An increase in revenue due to higher production volumes, offset by a decrease in realized pricing;

• An offsetting increase in operating expenses as a result of higher production volumes;

• An offsetting increase in cash G&A expense due to increase personnel costs, and;

• Changes related to timing of working capital payments and receipts.

Production, realized prices, and operating expenses are discussed below in Results of Operations. See “Note 8 – Derivative Instruments and Hedging Activities” and “Note 9 – Fair Value Measurements” of the Notes to our Consolidated Financial Statements for a reconciliation of the components of the Company’s derivative contracts and disclosures related to derivative instruments including their composition and valuation.

Investing activities. Net cash used in investing activities was $388.4 million and $1,324.1 million for the years ended December 31, 2019 and 2018, respectively. The change in investing activities was primarily attributable to the following:

• A $285.4 million increase in proceeds received from the sale of non-core assets as compared to the year ended December 31, 2018.

• A $676.5 million decrease in acquisitions.

• A $29.4 million increase in capital expenditures due to increased activity from our 2019 development program, focused on multi-well pads, as well as additional investments in facilities and infrastructure.

Our investing activities, on a cash basis, include the following for the periods indicated:

	Years Ended December 31,
	2019			2018			$ Change
	(In thousands)
Operational expenditures		$520,614			$537,514			($16,900	)
Seismic, leasehold and other	8,984			8,555			429
Capitalized general and administrative costs	31,612			24,383			7,229
Capitalized interest	79,330			40,721			38,609
Total capital expenditures (1)		$640,540			$611,173			$29,367
Acquisitions		$42,266			$718,793			($676,527	)
Proceeds from the sale of assets	(294,417		)	(9,009		)	(285,408		)
Additions to other assets	—			3,100			(3,100		)
Total investing activities		$388,389			$1,324,057			($935,668	)

(1) Includes activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

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On an accrual basis, which is the methodology used for establishing our annual capital budget, operational expenditures for the year ended December 31, 2019 were $506.1 million. Inclusive of seismic, leasehold and other, capitalized general and administrative, and capitalized interest costs, total capital expenditures for the year ended December 31, 2019 were $629.7 million.

General and administrative expenses and capitalized interest are discussed below in Results of Operations. See “Note 4 – Acquisitions and Divestitures” and “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information on significant acquisitions and drilling rig leases.

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, 2019, net cash used in financing activities was $90.6 million compared to net cash provided by financing activities of $844.5 million during the same period of 2018. The change in net cash provided by (used in) financing activities was primarily attributable to the following:

• Repayment of Carrizo’s credit facility and funded the redemption of preferred stock upon closing the Carrizo Acquisition.

• Redemption of Preferred Stock for approximately $73.0 million in 2019.

• Completed an underwritten public offering of 25.3 million shares of common stock for total estimated net proceeds of approximately $288.0 million in 2018.

• Issuance of Senior Notes due 2026, as defined below, for $394.0 million in net proceeds in 2018 in conjunction with the Delaware Asset Acquisition.

Net cash provided by (used in) financing activities includes the following for the periods indicated:

	Years Ended December 31,
	2019			2018			$ Change
	(In thousands)
Net borrowings on Credit Facility		$1,560,400			$175,000			$1,385,400
Repayment of Prior Credit Facility	(475,400		)	—			(475,400		)
Repayment of Carrizo credit facility	(853,549		)	—			(853,549		)
Repayment of Carrizo preferred stock	(220,399		)	—			(220,399		)
Issuance of 6.375% Senior Notes due 2026	—			400,000			(400,000		)
Issuance of common stock	—			287,988			(287,988		)
Payment of preferred stock dividends	(3,997		)	(7,295		)	3,298
Redemption of preferred stock	(73,017		)	—			(73,017		)
Payment of deferred financing costs	(22,480		)	(9,430		)	(13,050		)
Tax withholdings related to restricted stock units	(2,195		)	(1,804		)	(391		)
Net cash provided by (used in) financing activities		($90,637	)		$844,459			($935,096	)

See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information about the Company’s debt. See “Note 11 – Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional information about the Company’s equity offerings and the redemption of our Preferred Stock.

Senior Secured Credit Facility. Upon consummation of the Merger on December 20, 2019, the Company terminated the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) and entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. The borrowing base under the Credit Facility is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which hare not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.

As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion, and borrowings outstanding of $1.3 billion. The weighted average interest rate of our outstanding borrowings was 3.56%. The Company also had $17.7 million in letters of credit outstanding under the Credit Facility as of December 31, 2019.

Effective April 5, 2018, the Company entered into the first amendment to the Prior Credit Facility, as defined below, which (1) increased the borrowing base to $825.0 million, (2) increased the elected commitment amount to $650.0 million, (3) amended various covenants and terms to reflect current market trends, and (4) extended the maturity date to May 25, 2023.

Effective September 27, 2018, the Company entered into the second amendment to the Prior Credit Facility, which (1) increased the borrowing base to $1.1 billion, (2) increase the elected commitment amount to $850.0 million, and (3) amended various covenants and terms to reflect current market trends.

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Each of the first and second amendments to the Prior Credit Facility were terminated in conjunction with the termination of the Prior Credit Facility.

See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

Senior Notes

Upon consummation of the Merger, we became successor-in-interest to the indenture governing Carrizo’s 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) and the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The assumed Senior Notes are described below along with Callon’s legacy Senior Notes.

6.375% Senior Notes. On June 7, 2018, we issued $400.0 million aggregate principal amount of 6.375% Senior Notes due 2026 (the “6.375% Senior Notes”), which mature on July 1, 2026 and have interest payable semi-annually each January 1 and July 1. The net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, were used to fund a portion of the Delaware Asset Acquisition, described below. The 6.375% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

6.125% Senior Notes. On October 3, 2016, we issued $400.0 million aggregate principal amount of 6.125% Senior Notes with a maturity date of October 1, 2024 and interest payable semi-annually each April 1 and October 1. The 6.125% Senior Notes are guaranteed on a senior unsecured basis by our wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries. On May 19, 2017, we issued an additional $200.0 million aggregate principal amount of 6.125% Senior Notes which, with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes, are treated as a single class of notes under the indenture.

8.25% Senior Notes. The 8.25% Senior Notes have an aggregate principal amount of $250.0 million, mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, we may, at our option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, we may redeem all or a portion of the 8.25% Senior Notes at redemption prices decreasing annually from 106.188% to 100% of the principal amount redeemed plus accrued and unpaid interest.

6.25% Senior Notes. The 6.25% Senior Notes have an aggregate principal amount of $650.0 million, mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. We may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.

See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for additional information about our Senior Notes.

Preferred Stock. Holders of the Preferred Stock were entitled to receive, when, as and if declared by the 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). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million and $7.3 million for the years ended December 31, 2019 and 2018, respectively.

On June 18, 2019, we announced we had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). We recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock.

After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

See “Note 11 - Stockholders’ Equity” of the Notes to our Consolidated Financial Statements for additional discussion.

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2020 Capital Plan and Outlook

Our 2020 Capital Budget has been established at $975.0 million, which includes running an average of eight to nine drilling rig sand an average of three completion crews. Approximately 10-15% of the 2020 Capital Budget is comprised of infrastructure and facilities capital. As part of our 2020 operated horizontal drilling program, we expect to drill approximately 165 gross operated wells and complete approximately 160 gross operated wells. We currently expect to direct the majority of our 2020 Capital Budget towards opportunities in the Permian Basin. Additionally, we may consider divesting certain properties or assets that are not part of our core business or are no longer deemed essential to our future growth, provided we are able to divest such assets on terms that are acceptable to us.

Our revenues, earnings, liquidity and ability to grow are substantially dependent on the prices we receive for, and our ability to develop our proved reserves. We believe the long-term outlook for our business is favorable due to our resource base, low cost structure, financial strength, risk management, and disciplined investment of capital. We monitor current and expected market conditions, including the commodity price environment, and our liquidity needs and may adjust our capital investment plan accordingly.

Contractual Obligations

The following table includes our current contractual obligations and purchase commitments as of December 31, 2019: 

	Payments due by Period
	< 1 Year		Years 2 - 3		Years 4 - 5		> 5 Years		Total
	(In thousands)
6.25% Senior Notes (1)		$—		$—		$650,000		$—		$650,000
6.125% Senior Notes (1)	—		—		600,000		—		600,000
8.25% Senior Notes (1)	—		—		—		250,000		250,000
6.375% Senior Notes (1)	—		—		—		400,000		400,000
Credit Facility (2)	—		—		1,285,000		—		1,285,000
Interest expense and other fees related to debt commitments (3)	172,821		345,642		283,218		71,625		873,306
Drilling rig leases (4)	33,441		3,249		—		—		36,690
Operating leases	12,423		12,762		8,319		17,902		51,406
Delivery commitments (5)	9,563		24,417		23,970		39,298		97,248
Produced water disposal commitments (6)	14,947		26,901		5,957		1,840		49,645
Asset retirement obligations (7)	468		314		565		48,386		49,733
Other commitments	1,240		844		159		—		2,243
Total contractual obligations		$244,903		$414,129		$2,857,188		$829,051		$4,345,271

(1) Includes the outstanding principal amount only.

(2) The Credit Facility has a maturity date of December 20, 2024, subject to springing maturity dates as discussed above. See “Note 7 – Borrowings” of the Notes to our Consolidated Financial Statements for additional information.

(3) Includes estimated cash payments on the 6.25% Senior Notes, 6.125% Senior Notes, 8.25% Senior Notes, 6.375% Senior Notes, the Credit Facility and commitment fees calculated based on the unused portion of lender commitments as of December 31, 2019, at the applicable commitment fee rate.  

(4) Drilling rig leases represent future minimum expenditure commitments for drilling rig services under contracts to which the Company was a party on December 31, 2019. The value in the table represents the gross amount that we are committed to pay. However, we will record our proportionate share based on our working interest in our consolidated financial statements as incurred. See “Note 17 – Commitments and Contingencies” of the Notes to our Consolidated Financial Statements for additional information related to the Company’s drilling rig leases.

(5) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.

(6) Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

(7) Amounts represent our estimates of future asset retirement obligations. Because these costs typically extend many years into the future, estimating these future costs requires management to make estimates and judgments that are subject to future revisions based upon numerous factors, including the rate of inflation, changing technology and the political and regulatory environment. See “Note 14 – Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information.

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Other commitments

In July 2019, the Company executed a crude oil sales contract that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. We will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. 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.

In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. We will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, we will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by us and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

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Summary of Critical Accounting Policies

The following summarizes our critical accounting policies. See a complete list of significant accounting policies in “Note 2 – Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating DD&A of proved oil and natural gas property costs, the present value of estimated future net revenues included in the full cost ceiling test, estimates of future taxable income used in assessing the realizability of deferred tax assets, and the estimated timing of cash outflows underlying asset retirement obligations. There are numerous uncertainties inherent in the estimation of proved oil and gas reserves and in the projection of future rates of production and the timing of development expenditures. Other significant estimates are involved in determining asset retirement obligations, acquisition date fair values of assets acquired and liabilities assumed, impairments of unevaluated leasehold costs, fair values of commodity derivative assets and liabilities, fair values of contingent consideration arrangements, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.

Oil and natural gas properties

Oil and natural gas properties are accounted for using the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration and development activities are capitalized as oil and gas properties. The internal cost of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred.

Proceeds from the sale or disposition of evaluated and unevaluated oil and gas properties are accounted for as a reduction of evaluated oil and gas property costs, unless the sale significantly alters the relationship between capitalized costs and proved reserves in which case a gain or loss is recognized. For the years ended December 31, 2019 and 2018, we did not have any sales of oil and gas properties that significantly altered such relationship.

Capitalized oil and gas property costs within a cost center are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production amortization rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures (based on current costs) to be incurred in developing proved reserves, net of estimated salvage values.

Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on the properties or we determine that these costs have been impaired. We assesses properties on an individual basis or as 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 unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.

Write-down of Evaluated Properties

At the end of each quarter, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as an write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the 12-Month Average Realized Price, held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as we elected not to meet the criteria to qualify for hedge accounting treatment.

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Details of the 12-Month Average Realized Price of crude oil for the years ended December 31, 2019 and 2018 are summarized in the table below:

	Years Ended December 31,
	2019	2018
Write-down of evaluated oil and natural gas properties (In thousands)	$—	$—
Crude Oil 12-Month Average Realized Price ($/Bbl) - Beginning of period	$58.40	$49.48
Crude Oil 12-Month Average Realized Price ($/Bbl) - End of period	$53.90	$58.40
Crude Oil 12-Month Average Realized Price percentage increase (decrease)	(8%)	18%

The table below presents various pricing scenarios to demonstrate the sensitivity of our December 31, 2019 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, 2019 and, accordingly, does not consider drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, changes in crude oil and natural gas prices, and changes in development and operating costs occurring subsequent to December 31, 2019 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 could be required to make significant downward adjustments to the carrying value of our oil and natural gas properties.”

	12-Month Average Realized Prices		Excess of cost center ceiling over net book value, less related deferred income taxes	Increase (decrease) of cost center ceiling over net book value, less related deferred income taxes
Full Cost Pool Scenarios	Crude Oil ($/Bbl)	Natural Gas ($/Mcf)	(In millions)	(In millions)
December 31, 2019 Actual	$53.90	$1.55	$631
Crude Oil and Natural Gas Price Sensitivity
Crude Oil and Natural Gas +10%	$59.47	$1.85	$1,456	$825
Crude Oil and Natural Gas -10%	$48.33	$1.25	($369)	($1,000)
Crude Oil Price Sensitivity
Crude Oil +10%	$59.47	$1.55	$1,378	$747
Crude Oil -10%	$48.33	$1.55	($270)	($901)
Natural Gas Price Sensitivity
Natural Gas +10%	$53.90	$1.85	$702	$71
Natural Gas -10%	$53.90	$1.25	$546	($85)

We estimate that the first quarter of 2020 cost center ceiling will exceed the net book value, less related deferred income taxes, resulting in no write-down of evaluate oil and gas properties. This estimate of the first quarter of 2020 cost center ceiling test is based on an estimated 12-Month Average Realized Price of crude oil of $56.09 per barrel as of March 31, 2020, which is based on the average realized price for sales of crude oil on the first calendar day of each month for the first 11 months and an estimate for the twelfth month based on a quoted forward price.

Both of these estimates assume that all other inputs and assumptions are as of December 31, 2019, other than the price of crude oil, and remain unchanged. As such, drilling and completion activity, acquisitions or dispositions of oil and gas properties, production, and changes in development and operating costs occurring subsequent to December 31, 2019 may require revisions to estimates of proved reserves, which would impact the calculation of the cost center ceiling.

Estimating reserves and present value of estimated future net cash flows

Estimates of quantities of proved oil and natural gas reserves, including the discounted present value of estimated future net cash flows from such reserves at the end of each quarter, are based on numerous assumptions, which are likely to change over time. These assumptions include:

• the prices at which the Company can sell its production in the future. Oil, natural gas, and NGL prices are volatile, but we are required to assume that they remain constant, using the 12-Month Average Realized Price. In general, higher oil, natural gas, and NGL prices will increase quantities of estimated proved reserves and the present value of estimated future net cash flows from such reserves, while lower prices will decrease these amounts; and

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• the costs to develop and produce the Company’s reserves and the costs to dismantle its production facilities when reserves are depleted. These costs are likely to change over time, but we are required to assume that they remain constant. Increases in costs will reduce estimated proved reserves and the present value of estimated future net cash flows, while decreases in costs will increase such amounts.

Changes in these prices and/or costs will affect the present value of estimated future net cash flows more than the estimated proved reserves for the Company’s properties that have relatively short productive lives. If oil, natural gas, and NGL prices remain at current levels or decline further, it will have a negative impact on the present value of estimated future net cash flows and the estimated quantities of proved reserves.

In addition, the process of estimating proved oil and natural gas reserves requires that the Company’s independent and internal reserve engineers exercise judgment based on available geological, geophysical and technical information. We have described the risks associated with reserve estimation and the volatility of oil and natural gas prices under Part I, “Item 1A. Risk Factors.”

Asset retirement obligations

We record an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” of the Notes to our Consolidated Financial Statements for additional information.

Estimating the future plugging and abandonment costs of wells and related facilities requires management to make estimates and judgments because most of the obligations are many years in the future and asset removal technologies and costs are constantly changing, as are regulatory, political, environmental, safety and public relations considerations.

Derivative Instruments

To manage oil and natural gas price risk on a portion of our planned future production, we have historically utilized commodity derivative instruments (including collars, swaps, put and call options and other structures) on approximately 40% to 60% of our projected production volumes in any given year. We do not use these instruments for speculative purposes. Settlements of derivative contracts are generally based on the difference between the contract price and prices specified in the derivative instrument and a NYMEX price or other futures index price.

Our derivative positions are carried at their fair value on the balance sheet with changes in fair value recorded through earnings. The estimated fair value of our derivative contracts is based upon current forward market prices on NYMEX and in the case of collars and floors, the time value of options. For additional information regarding derivatives and their fair values, see “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” of the Notes to our Consolidated Financial Statements and “Part II, Item 7A. Quantitative and Qualitative Disclosures About Market Risk - Commodity Price Risk”.

Income 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 our deferred tax assets and reduce such assets by a valuation allowance if we deem it is more likely than not that some portion or all of the deferred tax assets will not be realized. Numerous judgments and assumptions are inherent in the determination of future taxable income, including factors such as future operating conditions (particularly as related to prevailing oil and natural gas prices). The Company had no valuation allowance as of December 31, 2019 and 2018. See “Note 12 - Income Taxes” of the Notes to our Consolidated Financial Statements for additional information regarding income taxes.

Accounting Standards Updates 

See “Note 2 - Summary of Significant Accounting Policies” of the Notes to our Consolidated Financial Statements for information discussion of recent accounting pronouncements issued by the Financial Accounting Standards Board.

Off-balance Sheet Arrangements

We had no off-balance sheet arrangements as of December 31, 2019.

55

ITEM 7A.  Quantitative and Qualitative Disclosures about Market Risk

We are exposed to a variety of market risks including commodity price risk, interest rate risk and counterparty and customer credit risk. We mitigate these risks through a program of risk management including the use of commodity derivative instruments.

Commodity price risk

The Company’s revenues are derived from the sale of its oil and natural gas production. The prices for oil and natural gas remain volatile and sometimes experience large fluctuations as a result of relatively small changes in supply, weather conditions, economic conditions and government actions. From time to time, the Company enters into derivative financial instruments to manage oil and natural gas 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, generally our objective is to hedge approximately 40% to 60% of our anticipated internally forecast production for the next 12 to 24 months, subject to the covenants under our Credit Facility. Our hedge policies and objectives may change significantly with movements in commodities prices or futures prices.

As of December 31, 2019, for the full year of 2020, the Company had 18,017,900 Bbls of fixed price oil hedges across NYMEX WTI, ICE Brent and Argus WTI-Houston benchmarks. The Company also had 8,476,700 Bbls of WTI Midland-Cushing oil basis hedges and 1,439,205 Bbls of WTI Houston-Cushing oil basis hedges. Additionally, for the full year of 2020, the Company had 7,320,000 MMBtus of fixed price NYMEX natural gas hedges and 21,596,000 MMBtus of Waha natural gas basis hedges. See “Note 8 - Derivative Instruments and Hedging Activities” of the Notes to our Consolidated Financial Statements for a description of the Company’s outstanding derivative contracts as of December 31, 2019.

The Company may utilize fixed price swaps, which reduce the Company’s exposure to decreases in commodity prices and limit the benefit the Company 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 Company 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-party to the collar pays the difference to the Company, and if the price rises above the ceiling, the counterparty receives the difference from the Company. Additionally, the Company 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’s net realized benefit from the three-way collar will be reduced on a dollar-for-dollar basis.

The Company may purchase put and call options, which reduce the Company’s 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.

The Company enters into these various agreements from time to time to reduce the effects of volatile oil and natural gas prices and does not enter into derivative transactions for speculative purposes. Presently, none of the Company’s derivative positions are designated as hedges for accounting purposes.

Interest rate risk

The Company is subject to market risk exposure related to changes in interest rates on our indebtedness under our Credit Facility. As of December 31, 2019, the Company had $1.3 billion outstanding under the Credit Facility with a weighted average interest rate of 3.56%. An increase or decrease of 1.00% in the interest rate would have a corresponding increase or decrease in our annual net income of approximately $12.9 million based on the balance outstanding at December 31, 2019. See “Note 7 - Borrowings” of the Notes to our Consolidated Financial Statements for more information on the Company’s interest rates on our Credit Facility. 

Counterparty and customer credit risk

The Company’s principal exposures to credit risk are through receivables from the sale of our oil and natural gas production, joint interest receivables and receivables resulting from derivative financial contracts.

The Company markets its oil and natural gas production to energy marketing companies. We are subject to credit risk due to the concentration of our oil and natural gas receivables with several significant customers. For the year ended December 31, 2019, four purchasers accounted for more than 10% of our revenue: Rio Energy International, Inc. (26%); Enterprise Crude Oil, LLC (19%); Plains Marketing, L.P.  (15%); and Shell Trading Company (10%). The inability of our significant customers to meet their obligations to us or their insolvency or liquidation may adversely affect our financial results. In order to mitigate potential exposure to credit risk, we may require from time to time for our customers to provide financial security. At December 31, 2019 our total receivables from the sale of our oil and natural gas production were approximately $165.3 million.

56

Joint interest receivables arise from billings to entities that own partial interests in the wells we operate. These entities participate in our wells primarily based on their ownership in leases on which we have or intend to drill. We have little ability to control whether these entities will participate in our wells. At December 31, 2019, our joint interest receivables were approximately $42.5 million.

Our oil and natural gas commodity derivative arrangements expose us to credit risk in the event of nonperformance by counterparties. Most of the counterparties on our commodity derivative instruments currently in place are lenders under our Credit Facility. We are likely to enter into additional commodity derivative instruments with these or other lenders under our Credit Facility, representing institutions with investment grade ratings. We have existing International Swap Dealers Association Master Agreements (“ISDA Agreements”) with our commodity derivative counterparties. The terms of the ISDA Agreements provide us and the counterparties with rights of offset upon the occurrence of defined acts of default by either us or a counterparty to a commodity derivative, whereby the party not in default may offset all commodity derivative liabilities owed to the defaulting party against all commodity derivative asset receivables from the defaulting party. At December 31, 2019, we had a net commodity derivative liability position of $24.8 million.

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ITEM 8.  Financial Statements and Supplementary Data

	Page
Reports of Independent Registered Public Accounting Firm	59
Consolidated Balance Sheets as of December 31, 2019 and 2018	63
Consolidated Statements of Operations for the Years Ended December 31, 2019, 2018 and 2017	64
Consolidated Statements of Stockholders’ Equity for the Years Ended December 31, 2019, 2018 and 2017	65
Consolidated Statements of Cash Flows for the Years Ended December 31, 2019, 2018 and 2017	66
Notes to Consolidated Financial Statements	67

58

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Callon Petroleum Company

Opinion on the financial statements

We have audited the accompanying consolidated balance sheets of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019 and 2018, the related consolidated statements of operations, stockholders’ equity, and cash flows for each of the three years in the period ended December 31, 2019, and the related notes (collectively referred to as the “financial statements”). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2019 and 2018, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2019, in conformity with accounting principles generally accepted in the United States of America.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the Company’s internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”), and our report dated February 28, 2020 expressed an unqualified opinion.

Change in accounting principle

As discussed in Note 2 to the consolidated financial statements, the Company has changed its method of accounting for leases in the year ended December 31, 2019 due to the adoption of FASB Accounting Standards Codification Topic 842, Leases.

Basis for opinion

These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence supporting 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.

Depletion expense and impairment of oil and gas properties impacted by the Company’s estimation of proved reserves

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.

59

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of depletion expense and potential impairment. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating depletion expense and assessing the Company’s oil and gas properties for potential impairment.

• We evaluated the independence, objectivity, and professional qualifications of the Company’s reserve engineers, made inquiries of those specialists regarding the process followed and judgments made to estimate the Company’s proved reserve volumes, and read the reserve report prepared by the Company’s specialists.

• To the extent key inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:

• Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

• Tested models used to estimate the future operating costs in the reserve report and compared amounts to historical operating costs;

• Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the reserve report to amounts expended for recently drilled and completed wells;

• Tested the working and net revenue interests used in the reserve report by inspecting land and division order records;

• Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

• Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report.

Fair value of oil and gas properties acquired impacted by the Company’s estimation of proved reserves

As described in Note 4 to the financial statements, the Company acquired Carrizo Oil & Gas, Inc. which requires management to make estimates of fair values associated with proved reserve volumes. 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 fair value. We identified the estimation of proved reserves of oil and gas properties acquired as a critical audit matter.

The principal consideration for our determination that the estimation of proved reserves is a critical audit matter is that changes in certain inputs and assumptions, which require a high degree of subjectivity, necessary to estimate the volume and future net revenues of the Company’s proved reserves could have a significant impact on the measurement of fair value. In turn, auditing those inputs and assumptions required subjective and complex auditor judgment.

Our audit procedures related to the estimation of proved reserves included the following, among others.

• We tested the design and operating effectiveness of controls relating to management’s estimation of proved reserves for the purpose of estimating the fair value assigned to proved properties.

• 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 those specialists.

• We evaluated the independence, objectivity, and professional qualifications of the Company’s valuation specialists, made inquiries of those valuation specialists regarding the process followed and judgments made to determine the fair value associated with proved reserve volumes, and read the valuation report prepared by the external specialists.

60

• To the extent key sensitive inputs and assumptions used to determine proved reserve volumes and other cash flow inputs and assumptions are derived from the Company’s accounting records or other third party information, including, but not limited to: historical pricing differentials, operating costs, estimated capital costs, and ownership interests, we tested management’s process for determining the assumptions, including examining the underlying support on a sample basis. Specifically, our audit procedures involved testing management’s assumptions by performing the following:

• Compared the estimated pricing differentials used in the reserve report to realized prices related to revenue transactions recorded in the current year and examined contractual support for the pricing differentials;

• Tested models used to estimate the future operating costs in the acquisition reserve report and compared amounts to historical operating costs;

• Evaluated the method used to determine the future capital costs and compared estimated future capital expenditures used in the valuation reserve report to amounts expended for recently drilled and completed wells;

• Evaluated the working and net revenue interests used in the reserve report by inspecting land and division order records;

• Evaluated the risk adjustments applied to proved reserve volumes by comparing against industry accepted factors;

• Evaluated the Company’s evidence supporting the amount of proved undeveloped properties reflected in the reserve report by examining historical conversion rates and support for the Company’s ability to fund and intent to develop the proved undeveloped properties; and

• Applied analytical procedures to the reserve report forecasted production by comparing to historical actual results, and to the prior year reserve report.

/s/ GRANT THORNTON LLP

We have served as the Company’s auditor since 2016.

Houston, Texas

February 28, 2020

61

Report of Independent Registered Public Accounting Firm

Board of Directors and Stockholders

Callon Petroleum Company

Opinion on internal control over financial reporting

We have audited the internal control over financial reporting of Callon Petroleum Company (a Delaware corporation) and subsidiaries (the “Company”) as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (“COSO”). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2019, based on criteria established in the 2013 Internal Control—Integrated Framework issued by COSO.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (“PCAOB”), the consolidated financial statements of the Company as of and for the year ended December 31, 2019, and our report dated February 28, 2020 expressed an unqualified opinion on those financial statements.

Basis for opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s report on internal control over financial reporting (“Management’s Report”). Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Our audit of, and opinion on, the Company’s internal control over financial reporting does not include the internal control over financial reporting of Carrizo Oil & Gas, Inc., a wholly-owned subsidiary, whose financial statements reflect total assets and revenues constituting 43 and 4 percent, respectively, of the related consolidated financial statement amounts as of and for the year ended December 31, 2019. As indicated in Management’s Report, Carrizo Oil & Gas, Inc. was acquired during 2019. Management’s assertion on the effectiveness of the Company’s internal control over financial reporting excluded internal control over financial reporting of Carrizo Oil & Gas, Inc.

Definition and limitations of internal control over financial reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ GRANT THORNTON LLP

Houston, Texas

February 28, 2020

62

Callon Petroleum Company

Consolidated Balance Sheets

(In thousands, except par and share data)

	December 31,
	2019	2018
ASSETS
Current assets:
Cash and cash equivalents	$13,341	$16,051
Accounts receivable, net	209,463	131,720
Fair value of derivatives	26,056	65,114
Other current assets	19,814	9,740
Total current assets	268,674	222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	4,682,994	2,314,345
Unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties, net	6,669,118	3,718,858
Operating lease right-of-use assets	63,908	—
Other property and equipment, net	35,253	21,901
Deferred tax asset	115,720	—
Deferred financing costs	22,233	6,087
Fair value of derivatives	9,216	—
Other assets, net	10,716	9,702
Total assets	$7,194,838	$3,979,173
LIABILITIES AND STOCKHOLDERS’ EQUITY
Current liabilities:
Accounts payable and accrued liabilities	$511,622	$285,849
Operating lease liabilities	42,858	—
Fair value of derivatives	71,197	10,480
Other current liabilities	26,570	18,587
Total current liabilities	652,247	314,916
Long-term debt	3,186,109	1,189,473
Operating lease liabilities	37,088	—
Asset retirement obligations	48,860	10,405
Deferred tax liability	—	9,564
Fair value of derivatives	32,695	7,440
Other long-term liabilities	14,531	2,167
Total liabilities	3,971,530	1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, respectively	—	15
Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, respective; 396,600,022 and 227,582,575 shares outstanding, respectively	3,966	2,276
Capital in excess of par	3,198,076	2,477,278
Retained earnings (Accumulated deficit)	21,266	(34,361	)
Total stockholders’ equity	3,223,308	2,445,208
Total liabilities and stockholders’ equity	$7,194,838	$3,979,173

The accompanying notes are an integral part of these consolidated financial statements. 

63

Callon Petroleum Company

Consolidated Statements of Operations

(In thousands, except per share data)

	For the Year Ended December 31,
	2019			2018			2017
Operating Revenues:
Oil		$633,107			$530,898			$322,374
Natural gas	36,390			56,726			44,100
Natural gas liquids	2,075			—			—
Total operating revenues	671,572			587,624			366,474
Operating Expenses:
Lease operating	91,827			69,180			49,907
Production taxes	42,651			35,755			22,396
Depreciation, depletion and amortization	240,642			182,783			116,391
General and administrative	45,331			35,293			27,067
Merger and integration expenses	74,363			—			—
Settled share-based awards	3,024			—			6,351
Other operating expense	1,076			5,083			2,916
Total operating expenses	498,914			328,094			225,028
Income From Operations	172,658			259,530			141,446
Other (Income) Expenses:
Interest expense, net of capitalized amounts	2,907			2,500			2,159
(Gain) loss on derivative contracts	62,109			(48,544		)	18,901
Loss on extinguishment of debt	4,881			—			—
Other income	(468		)	(2,896		)	(1,311		)
Total other (income) expense	69,429			(48,940		)	19,749
Income Before Income Taxes	103,229			308,470			121,697
Income tax expense	35,301			8,110			1,273
Net Income		$67,928			$300,360			$120,424
Preferred stock dividends	(3,997		)	(7,295		)	(7,295		)
Loss on redemption of preferred stock	(8,304		)	—			—
Income Available to Common Stockholders		$55,627			$293,065			$113,129
Income Available to Common Stockholders Per Common Share:
Basic		$0.24			$1.35			$0.56
Diluted		$0.24			$1.35			$0.56
Weighted Average Common Shares Outstanding:
Basic	233,140			216,941			201,526
Diluted	233,550			217,596			202,102

The accompanying notes are an integral part of these consolidated financial statements.

64

Callon Petroleum Company

Consolidated Statements of Stockholders’ Equity

(In thousands, except share amounts)

										Retained
	Preferred					Common		Capital in		Earnings			Total
	Stock					Stock		Excess		(Accumulated			Stockholders'
	Shares		$			Shares	$	of Par		Deficit)			Equity
Balance at 12/31/2016	1,459		$15			201,041	$2,010	$2,171,514			($440,137	)	$1,733,402
Net income	—		—			—	—	—		120,424			120,424
Shares issued pursuant to employee benefit plans	—		—			26	—	311		—			311
Restricted stock	—		—			769	8	9,098		—			9,106
Common stock issued	—		—			—	—	18		—			18
Impact of forfeiture estimate	—		—			—	—	418		(418		)	—
Preferred stock dividend	—		—			—	—	—		(7,295		)	(7,295	)
Balance at 12/31/2017	1,459		$15			201,836	$2,018	$2,181,359			($327,426	)	$1,855,966
Net income	—		—			—	—	—		300,360			300,360
Shares issued pursuant to employee benefit plans	—		—			45	—	533		—			533
Restricted stock	—		—			402	5	7,651		—			7,656
Common stock issued	—		—			25,300	253	287,735		—			287,988
Preferred stock dividend	—		—			—	—	—		(7,295		)	(7,295	)
Balance at 12/31/2018	1,459		$15			227,583	$2,276	$2,477,278			($34,361	)	$2,445,208
Net income	—		—			—	—	—		67,928			67,928
Shares issued pursuant to employee benefit plans	—		—			24	—	154		—			154
Restricted stock	—		—			779	8	11,622		—			11,630
Common stock issued for Carrizo Acquisition	—		—			168,214	1,682	763,691		—			765,373
Common stock warrants reissued for Carrizo Acquisition	—		—			—	—	10,029		—			10,029
Preferred stock dividend	—		—			—	—	—		(3,997		)	(3,997	)
Preferred stock redemption	(1,459	)	(15		)	—	—	(64,698	)	—			(64,713	)
Loss on redemption of preferred stock	—		—			—	—	—		(8,304		)	(8,304	)
Balance at 12/31/2019	—			$—		396,600	$3,966	$3,198,076		$21,266			$3,223,308

The accompanying notes are an integral part of these consolidated financial statements.

65

Callon Petroleum Company

Consolidated Statements of Cash Flows

(In thousands)

	Years Ended December 31,
	2019		2018		2017
Cash flows from operating activities:
Net income	$67,928		$300,360		$120,424
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	245,936		185,605		118,728
Amortization of non-cash debt related items	2,907		2,483		2,150
Deferred income tax expense	35,301		8,110		1,273
(Gain) loss on derivative contracts	62,109		(48,544	)	18,901
Cash paid for commodity derivative settlements, net	(3,789	)	(27,272	)	(8,472	)
(Gain) loss on sale of other property and equipment	(90	)	(144	)	62
Non-cash loss on early extinguishment of debt	4,881		—		—
Non-cash expense related to equity share-based awards	9,767		6,289		8,254
Change in the fair value of liability share-based awards	1,624		375		3,288
Payments to settle asset retirement obligations	(4,148	)	(1,469	)	(2,047	)
Payments for cash-settled restricted stock unit awards	(1,425	)	(4,990	)	(13,173	)
Changes in current assets and liabilities:
Accounts receivable	(35,071	)	(17,351	)	(44,495	)
Other current assets	(4,166	)	(7,601	)	108
Current liabilities	86,438		74,311		30,947
Other	8,114		(2,508	)	(6,057	)
Net cash provided by operating activities	476,316		467,654		229,891
Cash flows from investing activities:
Capital expenditures	(640,540	)	(611,173	)	(419,839	)
Acquisitions	(42,266	)	(718,793	)	(718,456	)
Acquisition deposit	—		—		45,238
Proceeds from sales of assets	294,417		9,009		20,525
Additions to other assets	—		(3,100	)	—
Net cash used in investing activities	(388,389	)	(1,324,057	)	(1,072,532	)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	2,455,900		500,000		25,000
Payments on senior secured revolving credit facility	(895,500	)	(325,000	)	—
Payment to terminate Prior Credit Facility	(475,400	)	—		—
Repayment of Carrizo’s senior secured revolving credit facility	(853,549	)	—		—
Repayment of Carrizo’s preferred stock	(220,399	)	—		—
Issuance of 6.125% Senior Notes due 2024	—		—		200,000
Premium on the issuance of 6.125% Senior Notes due 2024	—		—		8,250
Issuance of 6.375% Senior Notes due 2026	—		400,000		—
Issuance of common stock	—		287,988		—
Payment of preferred stock dividends	(3,997	)	(7,295	)	(7,295	)
Payment of deferred financing costs	(22,480	)	(9,430	)	(7,194	)
Tax withholdings related to restricted stock units	(2,195	)	(1,804	)	(1,118	)
Redemption of preferred stock	(73,017	)	—		—
Net cash provided by (used in) financing activities	(90,637	)	844,459		217,643
Net change in cash and cash equivalents	(2,710	)	(11,944	)	(624,998	)
Balance, beginning of period	16,051		27,995		652,993
Balance, end of period	$13,341		$16,051		$27,995

The accompanying notes are an integral part of these consolidated financial statements.

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Draft 1

INDEX TO THE NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

1.	Description of Business	11.	Stockholders’ Equity
2.	Summary of Significant Accounting Policies	12.	Income Taxes
3.	Revenue Recognition	13.	Leases
4.	Acquisitions and Divestitures	14.	Asset Retirement Obligations
5.	Property and Equipment, Net	15.	Accounts Receivable, Net
6.	Earnings Per Share	16.	Accounts Payable and Accrued Liabilities
7.	Borrowings	17.	Commitments and Contingencies
8.	Derivative Instruments and Hedging Activities	18.	Subsequent Events (Unaudited)
9.	Fair Value Measurements	19.	Supplemental Information on Oil and Natural Gas Operations (Unaudited)
10.	Share-Based Compensation	20.	Supplemental Quarterly Financial Information (Unaudited)

Note 1 – Description of Business

Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 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. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

Callon is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. In 2019, through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company doubled its core acreage position in the Delaware Basin and entered the Eagle Ford Shale. The Company’s primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generating business in the Eagle Ford Shale.

Note 2 – Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved 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, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

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Accounts Receivable, Net

Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all period presented.

Concentration of Credit Risk and Major Customers

The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented:

	Years Ended December 31,
	2019	2018	2017
Rio Energy International, Inc.	26%	28%	17%
Enterprise Crude Oil, LLC	19%	14%	18%
Plains Marketing, L.P.	15%	21%	29%
Shell Trading Company	10%	*	*

* - Less than 10% for the applicable year.

The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 

Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship.

Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on 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 unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.

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Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as a write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did not recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. 

Other Property and Equipment

The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.

Deferred Financing Costs

Deferred financing costs associated with the Company’s senior notes are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-line method over the terms of the related senior notes. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Amortization of deferred financing costs, net of amortization of premiums, of $2.9 million, $2.5 million and $2.2 million were recorded for the years ended December 31, 2019, 2018 and 2017, respectively. 

Asset Retirement Obligations

The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information.

Derivative Instruments

The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes.

The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which

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the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion.

Revenue Recognition

The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “Note 3 - Revenue Recognition” for further discussion.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. As of December 31, 2019 and 2018, the Company did not have a valuation allowance against its deferred tax assets. See “Note 12 - Income Taxes” for further discussion.

Share-Based Compensation

The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below.

RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years). 

Cash SARs. Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. 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 will expire between one and seven years, depending on the date of grant.

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Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Interest paid, net of capitalized amounts		$—			$—			$—
Income taxes paid (1)	—			—			—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$3,414			$—			$—
Investing cash flows from operating leases	32,529			—			—
Non-cash investing and financing activities:
Change in accrued capital expenditures		($31,475	)		($52,757	)		($39,532	)
Change in asset retirement costs	13,559			8,730			(607		)
Contingent consideration arrangement	8,512			—			—
ROU assets obtained in exchange for lease liabilities:
Operating leases		$66,914			$—			$—
Financing leases	2,197			—			—

(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2019.

Earnings per Share

The Company’s basic net income attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. See “Note 6 - Earnings Per Share” for further discussion.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of crude oil, NGLs, and natural gas. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.

Recently Adopted Accounting Standards

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”).

Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

Upon adoption, the Company implemented policy elections and practical expedients which include the following:

• package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance

• excluding ROU assets and lease liabilities for leases with terms that are less than one year;

• combining lease and non-lease components and accounting for them as a single lease (elected by asset class);

• excluding land easements that existed or expired prior to adoption; and

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• policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.

Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion.

Recently Issued ASUs

None that are expected to have a material impact on our financial statements.

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.

Natural gas sales

Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs associated with certain contracts is included in natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. For other contracts that were assumed in the Carrizo Acquisition, defined below, where the Company maintains control throughout processing, the Company records NGL revenue separately on its consolidated statement of operations and presents the gathering a treating fees as an expense recorded in lease operating expense.

For the majority of the Company’s natural gas sales processing contracts, gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company modified the presentation of revenues and expenses to include these fees net of revenues effective January 1, 2018 upon adopting ASC 606 - Revenue from Contracts with Customers. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the year ended December 31, 2017, $3.4 million of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2019 and 2018 of $165.3 million and $87.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The increase from December 31, 2018 is primarily due to the Carrizo Acquisition.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

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Note 4 – Acquisitions and Divestitures

2019 Acquisitions and Divestitures

Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details.

The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Consideration:
Fair value of the Company’s common stock issued		$765,373
Total consideration		$765,373
Liabilities:
Accounts payable		$37,657
Revenues and royalties payable	52,449
Operating lease liabilities - current	29,924
Fair value of derivatives - current	61,015
Other current liabilities	82,084
Long-term debt	1,984,135
Operating lease liabilities - non-current	30,070
Asset retirement obligation	26,151
Fair value of derivatives - non-current	26,960
Other long-term liabilities	17,260
Common stock warrants	10,029
Total liabilities assumed		$2,357,734
Assets:
Accounts receivable, net		$48,479
Fair value of derivatives - current	17,451
Other current assets	4,945
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	682,928
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	159,320
Operating lease right-of-use-assets	59,994
Other long term assets	2,578
Total assets acquired		$3,123,107

Approximately $28.6 million of revenues and $7.0 million of direct operating expenses attributed to the Carrizo Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on December 20, 2019 through December 31, 2019.

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Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.

	Years Ended December 31,
	2019		2018
	(In thousands)
Revenues		$1,620,357		$1,661,171
Income from operations	614,668		767,628
Net income	369,777		734,527
Basic earnings per common share	0.89			$1.87
Diluted earnings per common share	0.89			$1.87

During 2019, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $74.4 million comprised of severance costs of $28.8 million and other merger and integration expenses of $45.6 million. As of December 31, 2019, $52.4 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.

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 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 includes 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.

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2018 Acquisitions and Divestitures

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock offering completed on May 30, 2018 and the issuance of the 6.375% Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings.

The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$253,089
Unevaluated properties	287,000
Total oil and natural gas properties		$540,089
Total assets acquired		$540,089
Liabilities
Asset retirement obligations		($570	)
Total liabilities assumed		($570	)
Net Assets Acquired		$539,519

Approximately $27.3 million of revenues and $9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition.

	Years Ended December 31,
	2018		2017
	(In thousands)
Revenues		$669,236		$469,896
Income from operations	299,090		209,723
Net income	324,318		181,406
Basic earnings per common share	$1.49		$0.90
Diluted earnings per common share	$1.49		$0.90

Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $87.9 million.

The Company did not have any material divestitures for the year ended December 31, 2018.

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2017 Acquisitions and Divestitures

Ameredev Acquisition. On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646.6 million, excluding customary purchase price adjustments (the “Ameredev Acquisition”). The Company partially funded the Ameredev Acquisition with net proceeds from the common stock offering completed on December 19, 2016. The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Acquisition.

The Ameredev Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$137,368
Unevaluated properties	509,359
Total oil and natural gas properties		$646,727
Total assets acquired		$646,727
Liabilities
Asset retirement obligations		($168	)
Total liabilities assumed		($168	)
Net Assets Acquired		$646,559

Approximately $36.1 million of revenues and $8.5 million of direct operating expenses attributed to the Ameredev Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on February 13, 2017 through December 31, 2017.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Ameredev Acquisition.

	Year Ended December 31, 2017
	(In thousands)
Revenues		$369,527
Income from operations	144,104
Net income	115,787
Basic earnings per common share		$0.57
Diluted earnings per common share		$0.57

Other. On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Acquisition discussed above, for aggregate net cash consideration of approximately $52.0 million. The Company funded the cash purchase price with available cash and proceeds from the issuance of an additional $200.0 million of its 6.125% Senior Notes. See “Note 7 - Borrowings” for further details of this offering.

The Company did not have any material divestitures for the year ended December 31, 2017.

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Note 5 – Property and Equipment, Net

As of December 31, 2019 and 2018, total property and equipment, net consisted of the following:

	As of December 31,
	2019			2018
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Accumulated depreciation, depletion, amortization and impairments	(2,520,488		)	(2,270,675		)
Net evaluated oil and natural gas properties	4,682,994			2,314,345
Unevaluated properties
Unevaluated leasehold and seismic costs	1,843,725			1,316,190
Capitalized interest	142,399			88,323
Total unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties, net		$6,669,118			$3,718,858
Other property and equipment		$67,202			$38,463
Accumulated depreciation	(31,949		)	(16,562		)
Other property and equipment, net		$35,253			$21,901

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $36.2 million, $28.0 million and $20.3 million for the years ended December 31, 2019, 2018 and 2017, respectively. The Company capitalized interest costs to unproved properties totaling $78.5 million, $56.2 million and $33.8 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following:

	2019		2018		2017		2016		Total
	(In thousands)
Acquisition costs		$682,413		$383,238		$577,959		$115,833		$1,759,443
Exploration costs	43,174		22,384		18,724		—		84,282
Capitalized interest	78,492		56,151		7,756		—		142,399
Total unevaluated properties		$804,079		$461,773		$604,439		$115,833		$1,986,124

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Note 6 – Earnings Per Share

Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended December 31,
	2019			2018			2017
	(In thousands, except per share amounts)
Net income		$67,928			$300,360			$120,424
Preferred stock dividends	(3,997		)	(7,295		)	(7,295		)
Loss on redemption of preferred stock	(8,304		)	—			—
Income available to common stockholders		$55,627			$293,065			$113,129
Basic weighted average common shares outstanding	233,140			216,941			201,526
Dilutive impact of restricted stock	410			655			576
Diluted weighted average common shares outstanding	233,550			217,596			202,102
Income Available to Common Stockholders Per Common Share
Basic		$0.24			$1.35			$0.56
Diluted		$0.24			$1.35			$0.56
Restricted stock (1)	998			89			16

(1) Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

Note 7 – Borrowings

The Company’s borrowings consisted of the following:

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	As of December 31,
	2019			2018
	(In thousands)
Senior Secured Revolving Credit Facility due 2024		$1,285,000			$200,000
6.25% Senior Notes due 2023 (1)	650,000			—
6.125% Senior Notes due 2024	600,000			600,000
8.25% Senior Notes due 2025 (1)	250,000			—
6.375% Senior Notes due 2026	400,000			400,000
Total principal outstanding	3,185,000			1,200,000
Unamortized premium for 6.125% Senior Notes	5,344			6,469
Unamortized premium for 6.25% Senior Notes	4,838			—
Unamortized premium for 8.25% Senior Notes	5,286			—
Unamortized deferred financing costs for Senior Notes	(14,359		)	(16,996		)
Total carrying value of borrowings (2)		$3,186,109			$1,189,473

(1) As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25% Senior Notes and 8.25% Senior Notes.

(2) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $6.1 million as of December 31, 2019 and 2018, respectively.

Senior Secured Revolving Credit Facility

On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) with a syndicate of lenders. The Prior Credit Facility provided for interest-only payments until May 25, 2023, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $2.0 billion.

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Effective May 1, 2019, the Company entered into the third amendment to the Prior Credit Facility to, among other things: (i) reaffirm the borrowing base at $1.1 billion, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends.

As a result of entering into the Credit Facility, as defined below, the Company terminated the Prior Credit Facility. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility.

On December 20, 2019, upon consummation of the Merger, the Company entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. The borrowing base under the Credit Facility is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.

As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion, and borrowings outstanding of $1.3 billion at a weighted average interest rate of 3.56%. The Company also had $17.7 million in letters of credit outstanding under the Credit Facility.

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 0.25% to 1.25%, 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 Eurodollar loan plus a margin between 1.25% to 2.25%. At any time the Leverage Ratio, as defined in the credit agreement, is greater than 3.00 to 1.00, the base rate and Eurodollar loans are increased 0.25%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations.

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. The Company used the net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above. The 6.375% 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. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, 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 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022, and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022, but before July 1, 2023, and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023, but before July 1, 2024, and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024.

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.

6.125% Senior Notes

On October 3, 2016, the Company issued $400.0 million aggregate principal amount of 6.125% Senior Notes due 2024 (the “6.125% Senior Notes), which mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. 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. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

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On May 19, 2017, the Company issued an additional $200.0 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The Company used a portion of the net proceeds from the offering of approximately $206.1 million, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, to fund the acquisition completed on June 5, 2017 with the remainder for general corporate purposes.

The Company may redeem all or a portion of the 6.125% Senior Notes at redemption prices decreasing from 104.594% to 100% of the principal amount on October 1, 2022, 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, if any, to the date of repurchase.

Senior Notes Assumed in Merger

On December 20, 2019, upon consummation of the Merger, the Company became successor-in-interest to the indenture governing the 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) and the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.

8.25% Senior Notes. The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, 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.

6.25% Senior Notes. The 6.25% Senior Notes mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.

If a Change of Control (as defined in the indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes also contains customary events of default, including those related to failure to comply with the terms of the 8.25% Senior Notes and the 6.25% Senior Notes, certain cross defaults of other indebtedness and mortgages, and certain failures to pay final judgments.

Restrictive covenants

The Company’s credit facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2019.

Note 8 – Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil and natural gas 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 production. The Company utilizes a mix of collars, swaps, and put and call options 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 risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. 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

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of offset under the agreements. Counterparty credit risk is considered when determining the fair value of a derivative instrument. “See Note 9 - Fair Value Measurements” for further discussion.

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. 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.

Financial statement presentation and settlements

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.

Contingent consideration arrangements

Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds in each of the next several years. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):

Year

Threshold (1)

Contingent Receipt - Annual

Threshold (1)

Contingent Receipt - Annual

Period Cash Flow Occurs

Statement of Cash Flows Presentation

Remaining Contingent Receipt - Aggregate Limit (3)

Divestiture Date Fair Value

$8,512

Pending Settlement

2019

Greater than $60/Bbl, less than $65/Bbl

$—

Equal to or greater than $65/Bbl

$—

1Q20

N/A

Remaining Potential Settlements

2020-2021

Greater than $60/Bbl, less than $65/Bbl

$9,000

Equal to or greater than $65/Bbl

$20,833

(2)

(2)

$60,000

(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.

(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

(3) The specified pricing threshold for 2019 was not met. As such, approximately $41.5 million remains for potential settlements in future years.

As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:

Contingent ExL Consideration

	Year	Threshold (1)		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Remaining Contingent Payments - Aggregate Limit				Acquisition Date Fair Value
						(In thousands)
														($69,171	)
Pending Settlement	2019		$50.00	1Q20	Investing		($50,000	)
Remaining Potential Settlements	2020-2021		$50.00	(2)	(2)		($50,000	)		($75,000	)	(3)

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities.

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(3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.

Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020.

See “Note 18 - Subsequent Events” for further discussion of the Company’s actual settlements of its contingent consideration arrangements subsequent to December 31, 2019.

Derivatives not designated as hedging instruments

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.

As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

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	As of December 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Commodity derivative instruments		$26,849			($17,511	)		$9,338
Contingent consideration arrangements	16,718			—			16,718
Fair value of derivatives - current		$43,567			($17,511	)		$26,056
Commodity derivative instruments	—			—			—
Contingent consideration arrangements	9,216			—			9,216
Fair value of derivatives - non current		$9,216			$—			$9,216
Commodity derivative instruments		($38,708	)		$17,511			($21,197	)
Contingent consideration arrangements	(50,000		)	—			(50,000		)
Fair value of derivatives - current		($88,708	)		$17,511			($71,197	)
Commodity derivative instruments	(12,935		)	—			(12,935		)
Contingent consideration arrangements	(19,760		)	—			(19,760		)
Fair value of derivatives - non current		($32,695	)		$—			($32,695	)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Fair value of derivatives - current		$78,091			($12,977	)		$65,114
Fair value of derivatives - current		($23,457	)		$12,977			($10,480	)
Fair value of derivatives - non current	(7,440		)	—			(7,440		)

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The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:

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	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Oil derivatives
Net gain (loss) on settlements		($11,188	)		($27,510	)		($9,067	)
Net gain (loss) on fair value adjustments	(62,125		)	72,973			(11,426		)
Total gain (loss) on oil derivatives	(73,313		)	45,463			(20,493		)
Natural gas derivatives
Net gain (loss) on settlements	7,399			238			594
Net gain (loss) on fair value adjustments	1,490			2,843			998
Total gain (loss) on natural gas derivatives	8,889			3,081			1,592
Contingent consideration arrangements
Net gain (loss) on fair value adjustments	2,315			—			—
Total gain (loss) on derivative contracts		($62,109	)		$48,544			($18,901	)

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Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019:

	For the Full Year of					For the Full Year of
Oil contracts (WTI)	2020					2021
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	13,176,000					—
Weighted average price per Bbl
Ceiling (short call)		$65.28				$	—
Floor (long put)		$55.38				$	—
Floor (short put)		$45.08				$	—
Short call contracts
Total volume (Bbls)	1,674,450			(1	)	4,825,300		(1)
Weighted average price per Bbl		$75.98					$63.62
Swap contracts
Total volume (Bbls)	1,303,900					—
Weighted average price per Bbl		$55.19					$—
Swap contracts with short puts
Total volume (Bbls)	2,196,000					—
Weighted average price per Bbl
Swap		$56.06					$—
Floor (short put)		$42.50					$—
Oil contracts (Brent ICE)
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	837,500					—
Weighted average price per Bbl
Ceiling (short call)		$70.00					$—
Floor (long put)		$58.24					$—
Floor (short put)		$50.00					$—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	8,476,700					4,015,100
Weighted average price per Bbl		($1.47	)				$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,439,205					—
Weighted average price per Bbl		$2.40					$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	504,500					—
Weighted average price per Bbl		$58.22					$—
Natural gas contracts (Henry Hub)
Collar contracts (three-way collars)
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu
Ceiling (short call)		$2.75					$—
Floor (long put)		$2.50					$—
Floor (short put)		$2.00					$—
Swap contracts
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu		$2.48					$—
Short call contracts
Total volume (MMBtu)	12,078,000					7,300,000
Weighted average price per MMBtu		$3.50					$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	21,596,000					—
Weighted average price per MMBtu		($1.04	)				$—

(1) Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.

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Note 9 – Fair Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable 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 which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair value of financial instruments

Cash, cash equivalents, and 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 Credit Facility approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior 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.

	2019				2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes		$650,000		$658,125		$—		$—
6.125% Senior Notes	600,000		611,130		600,000		558,000
8.25% Senior Notes	250,000		256,250		—		—
6.375% Senior Notes	400,000		405,424		400,000		372,000
Total		$1,900,000		$1,930,929		$1,000,000		$930,000

Assets and liabilities measured at fair value on a 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:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a 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. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion.

Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the 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.

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The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018:

	December 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$9,338			$—
Contingent consideration arrangements	—		25,934			—
Liabilities
Commodity derivative instruments	—		(34,132		)	—
Contingent consideration arrangements	—		(69,760		)	—
Total net assets (liabilities)		$—		($68,620	)		$—
	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$65,114			$—
Liabilities
Commodity derivative instruments	—		(17,920		)	—
Total net liabilities (liabilities)		$—		$47,194			$—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Acquisitions. The fair value of 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 the income approach based on inputs that are not observable in the market 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, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion.

Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 - Asset Retirement Obligations” for additional discussion.

Note 10 – Share-Based Compensation

2018 Omnibus Incentive Plan

The 2018 Omnibus Incentive Plan, which became effective May 10, 2018 following shareholder approval (the “2018 Plan”), authorized and reserved for issuance 9,400,000 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 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”). At December 31, 2019, there were 13,814,216 shares available for future share-based awards under the Amended and Restated 2018 Plan. 

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RSU Equity Awards

The following table summarizes RSU Equity Award activity for the years ended December 31, 2019, 2018 and 2017:

	RSU Equity Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	1,448			$10.81
Granted (1) (2)	1,173			$12.25
Vested (3)	(797	)		$11.35
Forfeited	(34	)		$9.57
Unvested at the end of the period	1,790			$11.54
For the Year Ended December 31, 2018
Unvested at the beginning of the period	1,790			$11.54
Granted (1)	872			$13.89
Vested (3)	(506	)		$9.56
Forfeited	(53	)		$11.43
Unvested at the end of the period	2,103			$13.24
For the Year Ended December 31, 2019
Unvested at the beginning of the period	2,103			$13.24
Granted (1)	1,881			$8.60
Vested (3)	(1,062	)		$12.35
Forfeited	(227	)		$10.59
Unvested at the end of the period	2,695			$10.57

(1) Includes 399,425, 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0% - 200% for the years ended December 31, 2019, 2018 and 2017, respectively.

(2) Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142% of target at issuance in 2017.

(3) The fair value of shares vested was $7.3 million, $6.3 million and $9.0 million during the years ended December 31, 2019, 2018 and 2017, respectively.

Performance-based RSU Equity Awards that vest are 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% of the base units awarded. 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	2019		2018		2017
Vesting Multiplier	100	%	142	%	142% - 200%
Target	88,790		83,002		258,406
Vested at end of performance period	88,790		117,862		441,232
Did not vest at end of performance period	—		—		—

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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, 2019, 2018 and 2017, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $4.3 million, $3.5 million, and $2.6 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, 2019, 2018 and 2017:

	Years Ended December 31,
Performance-based Awards	2019		2018		2017
Number of simulations	100,000		100,000		100,000
Expected term (in years)	2.9		2.6		2.6
Expected volatility	47.9	%	51.6	%	65.3	%
Risk-free interest rate	2.4	%	2.6	%	1.5	%
Dividend yield	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$10.78		$16.66		$16.06

As of December 31, 2019, unrecognized compensation costs related to unvested RSU Equity Awards were $15.1 million and will be recognized over a weighted average period of 1.3 years.

Cash-Settled RSU Awards

The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2019, 2018 and 2017:

	Cash-Settled RSU Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	734			$8.87
Granted	283			$12.13
Vested	(379	)		$9.61
Forfeited	(13	)		$9.54
Unvested at the end of the period	625			$9.88
For the Year Ended December 31, 2018
Unvested at the beginning of the period	625			$9.88
Granted	348			$14.16
Vested	(276	)		$9.04
Forfeited	(19	)		$12.05
Unvested at the end of the period	678			$12.36
For the Year Ended December 31, 2019
Unvested at the beginning of the period	678			$12.36
Granted	424			$8.14
Vested	(164	)		$12.02
Forfeited	(83	)		$11.58
Unvested at the end of the period	855			$10.41

All of the Company’s outstanding Cash-Settled RSU Awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of Cash-Settled RSU Awards 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% of the base units awarded.

For the year ended December 31, 2019, 147,492 performance-based Cash-Settled RSU Awards vested at 100% of their issued units, resulting in a payable amount of $0.7 million in 2020. Also during 2019, 16,600 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $0.1 million in 2019.

For the year ended December 31, 2018, 207,261 performance-based Cash-Settled RSU Awards subject to the peer performance-based vesting described above, vested between 100% to 163% of their issued units, depending on the date of the vesting, resulting in cash payments of $0.1 million in 2018 and $1.3 million in 2019. Also during 2018, 129,753 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $1.8 million during 2018.

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The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:

	December 31,
	2019		2018
Other current liabilities		$966		$1,390
Other long-term liabilities	2,089		2,067
Total Cash-Settled RSU Awards		$3,055		$3,457

As of December 31, 2019, the Company had the following performance-based Cash-Settled RSU Awards outstanding:

	Target Awards Outstanding	Potential Minimum Units Vesting	Potential Maximum Units Vesting
	(In thousands)
Vesting in 2020	292	—	586
Vesting in 2021	373	—	745
Vesting in 2022	—	—	—
Other	24	24	24
Total Cash-Settled RSU Awards	689	24	1,355

As of December 31, 2019, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $1.1 million and will be recognized over a weighted average period of 1.5 years.

Cash-Settled SARs

As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2019.

	Stock Appreciation Rights	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)
For the Year Ended December 31, 2019
Outstanding, beginning of period	—		$—
Granted	—		$—
Reissued	3,677,955		$10.03
Exercised	—		$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	3,677,955		$10.03	4.4		$—
Vested, end of period	3,677,955		$10.03	0		$—
Vested and exercisable, end of period	—		$—	0		$—

The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $4.6 million. The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below:

	2019		2018		2017		2016
Fair Value Inputs
Expected term (in years)	5.4		4.5		1.9		1.1
Expected volatility	60.7	%	56.9	%	58.6	%	68.1	%
Risk-free interest rate	1.7	%	1.7	%	1.6	%	1.5	%
Dividend yield	—	%	—	%	—	%	—	%
Acquisition date fair value per Cash SAR	$2.11		$1.42		$0.21		$0.10
Expiration date	March 17, 2026		March 17, 2025		March 23, 2022		March 17, 2021

The liability for Cash SARs as of December 31, 2019 was $5.0 million, all of which was classified as “Other current liabilities” in the consolidated balance sheets in the respective period. Changes to the fair value of the Cash SARs are included in “General and

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administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2019.

Share-Based Compensation Expense, Net

The following table presents share-based compensation expense for each respective period:

	Years Ended December 31,
	2019				2018				2017
Share-based compensation cost for:	Equity		Liability		Equity		Liability		Equity		Liability
RSU Equity Awards (1)		$14,322		$—		$9,460		$—		$10,225		$—
Cash-Settled RSU Awards (1)	—		1,021		—		336		—		4,294
Cash SARs	—		443		—		—		—		—
Total share-based compensation cost (2)		$14,322		$1,464		$9,460		$336		$10,225		$4,294

(1) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017.

(2) The portion of this share-based compensation cost that was included in “General and administrative” totaled $11.1 million, $6.4 million and $5.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, and the portion capitalized to oil and gas properties was $4.7 million, $3.4 million and $3.2 million for the years ended December 31, 2019, 2018, and 2017, respectively.

Note 11 – Stockholders’ Equity

Increase in Authorized Common Shares

As a result of the Carrizo Acquisition, the shareholders approved an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 525,000,000.

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s Preferred Stock were entitled to receive, when, as and if declared by the Company’s 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). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million, $7.3 million and $7.3 million for years ended December 31, 2019, 2018 and 2017, respectively.

On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). The Company recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock.

After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

Common Stock Offerings

On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $288.0 million. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition.

On December 19, 2016, the Company completed an underwritten public offering of 40.0 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634.9 million. Proceeds from the offering were used to partially fund the Ameredev Acquisition. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Ameredev Acquisition.

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Note 12 – Income Taxes 

The components of the Company’s income tax expense are as follows:

	Years Ended December 31,
	2019		2018		2017
	(In thousands)
Current
Federal		$—		$—		($48	)
State	220		—		—
Total current income tax expense (benefit)	220		—		(48		)
Deferred
Federal	33,584		3,594		(45		)
State	1,497		4,516		1,366
Total deferred income tax expense	35,081		8,110		1,321
Total income tax expense		$35,301		$8,110		$1,273

A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows:

	Years Ended December 31,
	2019		2018			2017
Income before income taxes		$103,229		$308,470			$121,697
Income tax expense computed at the statutory federal income tax rate	21,678		64,779			42,594
State income tax expense, net of federal benefit	1,253		3,568			1,273
Equity based compensation	1,222		(494		)	—
Non-deductible compensation	90		1,209			—
Non-deductible merger expenses	5,537		—			—
Statutory depletion carryforward	5,381		—			—
Other	140		168			—
Change in valuation allowance	—		(61,120		)	(42,594		)
Income tax expense		$35,301		$8,110			$1,273

At December 31, 2019, the Company recorded a tax expense of $5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes.

The Company recorded an income tax expense of $5.4 million related to the statutory depletion carryforward of $24.9 million. The percentage depletion deductions are in excess of the Company’s net depletable basis and can be carried forward indefinitely. The tax benefit for the special deduction will be recognized in the year the carryforward is deducted on the federal tax return.

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As of December 31, 2019 and 2018, the net deferred income tax assets and liabilities are comprised of the following:

	As of December 31,
	2019			2018
	(In thousands)
Deferred tax assets
Federal net operating loss carryforward		$110,703			$151,497
Interest expense carryforward	—			7,335
Statutory depletion carryforward	—			5,381
Asset retirement obligations	9,981			2,347
Derivative asset	14,823			—
Unvested RSU equity awards	4,928			2,751
Operating lease right-of-use assets	29,897			—
Other	10,445			991
Total deferred tax assets		$180,777			$170,302
Deferred income tax valuation allowance	—			—
Net deferred tax assets		$180,777			$170,302
Deferred tax liability
Oil and natural gas properties		($38,546	)		($169,682	)
Derivative liability	—			(10,184		)
Operating lease liabilities	(26,511		)	—
Total deferred tax liability		($65,057	)		($179,866	)
Net deferred tax asset (liability)		$115,720			($9,564	)

For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $159.3 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382 and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilized prior to expirations. The Company expects that these tax attributes will be fully utilized prior to expiration.

Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership 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, 2019, the Company had approximately $527.2 million of NOLs, including $288.2 million acquired from Carrizo, of which approximately $496.5 million expire between 2035 and 2037 and $30.7 million have an indefinite carryforward life. The Company expects that the NOL balance will be fully utilized prior to expiration.

Management 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. At December 31, 2019, management considered all factors including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income and determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

The Company had no significant unrecognized tax benefits at December 31, 2019. 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. In the Company’s major tax jurisdictions, the earliest year open to examination is 2015.

Note 13 – Leases

The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-

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line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

Types of Leases

The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.

Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.

Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations.

Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations.

The tables below, which present the components of lease costs and 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, 2019.

	Year Ended December 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs		$92
Amortization of right-of-use assets (1)	82
Interest on lease liabilities (2)	10
Operating lease cost (3)	38,076
Impairment of Operating lease ROU assets (4)	16,209
Short-term lease cost (5)	3,640
Variable lease costs (6)	—
Total lease costs		$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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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.

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The table below presents supplemental balance sheet information for the Company’s leases as of December 31, 2019.

	Year Ended December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$63,908
Current operating lease liabilities		$42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Financing leases:
Other property and equipment		$2,197
Accumulated depreciation	(82		)
Other property and equipment, net	2,115
Current financing lease liabilities		$1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	2,141

The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019.

	December 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4.3
Financing leases	2.1
Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	9.4	%

The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019.

	Operating Leases		Financing Leases
	(In thousands)
2020		$45,864		$1,475
2021	11,648		275
2022	4,363		234
2023	4,209		233
2024	4,110		38
Thereafter	17,902		—
Total lease payments	88,096		2,255
Less imputed interest	8,150		114
Total lease liabilities		$79,946		$2,141

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Note 14 – Asset Retirement Obligations

The table below summarizes the activity for the Company’s asset retirement obligations:

	Years Ended December 31,
	2019			2018
	(In thousands)
Asset retirement obligations, beginning of period		$14,292			$6,020
Accretion expense	945			874
Liabilities incurred	615			973
Increase due to acquisition of oil and gas properties	26,107			570
Liabilities settled	(3,394		)	(1,288		)
Dispositions	(1,776		)	(614		)
Revisions to estimates	12,944			7,757
Asset retirement obligations, end of period	49,733			14,292
Less: Current asset retirement obligations	(873		)	(3,887		)
Non-current asset retirement obligations		$48,860			$10,405

Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2019 and 2018 as long-term restricted investments were $3.5 million and $3.4 million, respectively, and 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,
	2019			2018
	(In thousands)
Oil and natural gas receivables		$165,275			$87,062
Joint interest receivables	42,493			42,373
Other receivables	3,231			3,150
Total	210,999			132,585
Allowance for doubtful accounts	(1,536		)	(865		)
Total accounts receivable, net		$209,463			$131,720

Note 16 – Accounts Payable and Accrued Liabilities

	As of December 31,
	2019		2018
	(In thousands)
Accounts payable		$238,758		$83,412
Revenues payable	145,816		94,114
Accrued capital expenditures	61,950		83,658
Accrued interest	36,295		24,665
Accrued severance (1)	28,803		—
Total accounts payable and accrued liabilities		$511,622		$285,849

(1)    See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

Note 17 – Commitments and 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

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associated with long-term, non-cancelable leases, drilling rig contracts and gathering, processing and transportation service agreements, which require minimum volumes of natural gas or produced water to be delivered, as of December 31, 2019.

	2020	2021	2022	2023	2024	2025 and Thereafter	Total
	(In thousands)
Operating leases	$12,423	$8,399	$4,363	$4,209	$4,110	$17,902	$51,406
Drilling rig contracts (1)	33,441	3,249	—	—	—	—	36,690
Delivery commitments (2)	9,563	13,437	10,980	11,553	12,417	39,298	97,248
Produced water disposal commitments (3)	14,947	14,968	11,933	4,387	1,570	1,840	49,645
Total	$70,374	$40,053	$27,276	$20,149	$18,097	$59,040	$234,989

(1) Drilling rig contracts 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.

(2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.

(3) Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

Operating leases

As of December 31, 2019, the Company had contracts for nine horizontal drilling rigs. The contract terms will end on various dates between January 2020 and May 2021.

Other commitments

In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. The Company will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. The Company will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

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Note 18 – Subsequent Events (Unaudited)

Contingent Consideration Arrangements

For the year ended December 31, 2019, the specified pricing thresholds related certain of the contingent consideration arrangements acquired in the Carrizo Acquisition were exceeded. As a result, in January 2020, the Company paid $50.0 million and received $10.0 million from settlement of a portion of these contingent consideration arrangements.

Note 19 - Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Estimated Reserves

The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). 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 Reserve Engineering Firms 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.

97

The following tables disclose changes in the estimated quantities of proved reserves, all of which are located onshore within the continental United States:

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	Years Ended December 31,
Proved reserves	2019		2018		2017
Oil (MBbls)
Beginning of period	180,097		107,072		71,145
Purchase of reserves in place	183,382		30,756		8,388
Sales of reserves in place	(17,980	)	—		—
Extensions and discoveries	45,663		67,763		39,267
Revisions to previous estimates	(33,136	)	(16,051	)	(5,171	)
Production	(11,665	)	(9,443	)	(6,557	)
End of period	346,361		180,097		107,072
Natural Gas (MMcf)
Beginning of period	350,466		179,410		122,611
Purchase of reserves in place	455,158		53,563		12,711
Sale of reserves in place	(86,856	)	—		—
Extensions and discoveries	82,566		103,149		48,648
Revisions to previous estimates	(24,482	)	29,791		6,336
Production	(19,718	)	(15,447	)	(10,896	)
End of period	757,134		350,466		179,410
NGLs (MBbls)
Beginning of period	—		—		—
Purchase of reserves in place	67,597		—		—
Production	(135	)	—		—
End of period	67,462		—		—
Total (MBoe)
Beginning of period	238,508		136,974		91,580
Purchase of reserves in place	326,838		39,683		10,507
Sale of reserves in place	(32,456	)	—		—
Extensions and discoveries	59,424		84,955		47,375
Revisions to previous estimates	(37,216	)	(11,086	)	(4,115	)
Production	(15,086	)	(12,018	)	(8,373	)
End of period	540,012		238,508		136,974

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	Years Ended December 31,
Proved developed reserves:	2019	2018	2017
Oil (MBbls)
Beginning of period	92,202	51,920	32,920
End of period	152,687	92,202	51,920
Natural gas (MMcf)
Beginning of period	218,417	104,389	61,871
End of period	320,676	218,417	104,389
NGLs (MBbls)
Beginning of period	—	—	—
End of period	24,844	—	—
Total proved developed reserves (MBoe)
Beginning of period	128,605	69,318	43,232
End of period	230,977	128,605	69,318
Proved undeveloped reserves
Oil (MBbls)
Beginning of period	87,895	55,152	38,225
End of period	193,674	87,895	55,152
Natural gas (MMcf)
Beginning of period	132,049	75,021	60,740
End of period	436,458	132,049	75,021
NGLs (MBbls)
Beginning of period	—	—	—
End of period	42,618	—	—
Total proved undeveloped reserves (MBoe)
Beginning of period	109,903	67,656	48,348
End of period	309,035	109,903	67,656
Total proved reserves
Oil (MBbls)
Beginning of period	180,097	107,072	71,145
End of period	346,361	180,097	107,072
Natural gas (MMcf)
Beginning of period	350,466	179,410	122,611
End of period	757,134	350,466	179,410
NGLs (MBbls)
Beginning of period	—	—	—
End of period	67,462	—	—
Total proved reserves (MBoe)
Beginning of period	238,508	136,974	91,580
End of period	540,012	238,508	136,974

Total Proved Reserves

The Company ended 2019 with estimated proved reserves of 540.0 MMBoe, representing a 126% increase over 2018 year-end estimated proved reserves of 238.5 MMBoe. The Company added 386.3 MMBoe primarily from the Carrizo Acquisition completed in the fourth quarter of 2019 and development efforts in the Permian Basin, where it drilled a total of 61 gross (53.7 net) wells. This increase was offset by 2019 production, sales of reserves of 32.5 MMBoe, which are primarily related to the Ranger Divestiture, and negative revisions of previous estimates of 37.2 MMBoe. The negative revisions include 9.8 MMBoe from the reclassifications of PUDs within our optimized our development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which allowed the Company to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. The remaining negative revisions were primarily from the observed impact of well spacing tests on producing wells and the related impact on reserve estimates as the Company advanced larger scale development concepts across its multi-zone inventory as well as the adverse effect of pricing and other economic factors.

The Company ended 2018 with estimated net proved reserves of 238.5 MMBoe, representing a 74% increase over 2017 year-end estimated net proved reserves of 137.0 MMBoe. The Company added 124.6 MMBoe primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross (57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2.0 MMBoe primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9.1 MMBoe from 19 PUD locations primarily due to

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acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.

The Company ended 2017 with estimated net proved reserves of 137.0 MMBoe, representing a 50% increase over 2016 year-end estimated net proved reserves of 91.6 MMBoe. The Company added 57.9 MMBoe 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, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD 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.

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,
	2019			2018
Oil and natural gas properties:	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties	9,189,606			5,989,533
Accumulated depreciation, depletion, amortization and impairment	(2,520,488		)	(2,270,675		)
Total oil and natural gas properties capitalized		$6,669,118			$3,718,858

Costs Incurred

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:

	Years Ended December 31,
	2019		2018		2017
Acquisition costs:	(In thousands)
Evaluated properties		$49,572		$347,305		$156,340
Unevaluated properties	107,347		466,816		499,295
Development costs	189,259		259,410		148,254
Exploration costs	309,013		323,458		239,453
Total costs incurred		$655,191		$1,396,989		$1,043,342

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, 2019. 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.

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	Years Ended December 31,
	2019		2018		2017
Oil ($/Bbl) (1)		$53.90		$58.40		$49.48
Natural gas ($/Mcf) (2)		$1.55		$3.64		$3.47
NGLs ($/Bbl)		$15.58		$—		$—

(1) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

(2) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.

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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,
	2019			2018			2017
	(In thousands)
Future cash inflows		$20,891,469			$11,794,080			$5,920,328
Future costs
Production	(6,717,088		)	(2,923,959		)	(1,692,871		)
Development and net abandonment	(3,058,861		)	(1,429,787		)	(680,948		)
Future net inflows before income taxes	11,115,520			7,440,334			3,546,509
Future income taxes	(941,768		)	(782,470		)	(166,985		)
Future net cash flows	10,173,752			6,657,864			3,379,524
10% discount factor	(5,222,726		)	(3,716,571		)	(1,822,842		)
Standardized measure of discounted future net cash flows		$4,951,026			$2,941,293			$1,556,682

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	Changes in Standardized Measure
	For the Year Ended December 31,
	2019			2018			2017
	(In thousands)
Standardized measure at the beginning of the period		$2,941,293			$1,556,682			$809,832
Sales and transfers, net of production costs	(579,744		)	(481,306		)	(294,172		)
Net change in sales and transfer prices, net of production costs	(387,970		)	222,802			176,234
Net change due to purchases of in place reserves	2,975,296			554,697			129,454
Net change due to sales of in place reserves	(303,526		)	—			—
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	607,146			1,001,873			635,000
Changes in future development cost	205,398			40,483			(8,148		)
Previously estimated development costs incurred	134,037			91,900			45,131
Revisions of quantity estimates	(420,488		)	(167,096		)	(79,325		)
Accretion of discount	314,921			157,676			80,983
Net change in income taxes	(210,641		)	(187,841		)	(20,073		)
Changes in production rates, timing and other	(324,696		)	151,423			81,766
Aggregate change	2,009,733			1,384,611			746,850
Standardized measure at the end of period		$4,951,026			$2,941,293			$1,556,682

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Draft 1

Note 20 - Supplemental Quarterly Financial Information (Unaudited)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018:

2019	First Quarter (2)			Second Quarter (3)		Third Quarter (4)		Fourth Quarter (5)
	(In thousands, except per share amounts)
Total operating revenues		$153,047			$167,052		$155,378		$196,095
Income from operations	43,225			58,509		52,544		18,380
Net income (loss)	(19,543		)	55,180		55,834		(23,543		)
Income (loss) available to common stockholders	(21,367		)	53,357		47,180		(23,543		)
Income (loss) available to common stockholders per common share (1)
Basic		($0.09	)		$0.23		$0.21		($0.09	)
Diluted		($0.09	)		$0.23		$0.21		($0.09	)

2018	First Quarter		Second Quarter (6)		Third Quarter (7)		Fourth Quarter (8)
	(In thousands, except per share amounts)
Total operating revenues		$127,440		$137,075		$161,214		$161,895
Income from operations	60,986		67,400		72,811		58,333
Net income	55,761		50,474		37,931		156,194
Income available to common stockholders	53,937		48,650		36,108		154,370
Income available to common stockholders per common share (1)
Basic		$0.27		$0.23		$0.16		$0.68
Diluted		$0.27		$0.23		$0.16		$0.68

(1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(2) First quarter of 2019 included the following:

a. $67.3 million loss on derivative contracts

(3) Second quarter of 2019 included the following:

a. $14.0 million gain on derivative contracts

(4) Third quarter of 2019 included the following:

a. $21.8 million gain on derivative contracts

b. $5.9 million of merger and integration costs associated with the merger with Carrizo

c. $8.3 million loss on redemption of Preferred Stock

(5) Fourth quarter of 2019 included the following:

a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

b. $68.4 million of merger and integration costs associated with the merger with Carrizo

c. $30.7 million loss on derivative contracts

d. $4.9 million loss on extinguishment of debt

(6) Second quarter of 2018 included the following:

a. $16.6 million loss on derivative contracts

(7) Third quarter of 2018 included the following:

a. $34.3 million loss on derivative contracts

(8) Fourth quarter of 2018 included the following:

a. 103.9 million gain on derivative contracts

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ITEM 9. Changes In and Disagreements with Accountants on Accounting and Financial Disclosure

None.

ITEM 9A.  Controls and Procedures

Disclosure controls and 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 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, 2019.

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. Under the supervision and with the participation of our management, including our CEO and CFO, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2019 based on the framework in Internal Control – Integrated Framework published by the Committee of Sponsoring Organizations (COSO) of the Treadway Commission (2013 framework) (the COSO criteria). Based on that evaluation, management concluded that our internal control over financial reporting was effective as of December 31, 2019. Management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Carrizo’s total assets and total operating revenue represented approximately 40% of the Company’s consolidated total assets at December 31, 2019 and 4% of the Company’s consolidated total operating revenue for the year ended December 31, 2019.

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, 2019, presented preceding the Company’s financial statements included in Part II, Item 8 of this 2019 Annual Report on Form 10-K. Additionally, the financial statements for the years ended December 31, 2018 and 2017, covered in this 2019 Annual Report on Form 10-K, have also been audited by the Company’s independent registered public accounting firm, whose report is presented preceding the their report on the Company’s internal control over financial reporting, included in Part II, Item 8.

Changes in internal control over financial reporting. As noted under “Management’s report on internal control over financial reporting”, management’s evaluation of, and conclusion on, the effectiveness of internal control over financial reporting did not include the internal controls of the entities acquired in the merger with Carrizo on December 20, 2019. Under guidelines established by the SEC, companies are permitted to exclude acquisitions from their assessment of internal control over financial reporting during the first year of an acquisition while integrating the acquired company. The Company is in the process of integrating Carrizo’s and our internal controls over financial reporting. As a result of these integration activities, certain controls will be evaluated and may be changed. Except as noted above, 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 9B. Other Information

None.

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PART III.

ITEM 10.  Directors, Executive Officers and Corporate Governance

For information concerning Item 10, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

The Company has adopted a code of ethics that applies to the Company’s officers, directors, employees, agents and representatives and includes a code of ethics for senior financial officers that applies to the Chief Executive Officer, Chief Financial Officer and Chief Accounting Officer. The full text of such code of ethics has been posted on the Company’s website at www.callon.com, and is available free of charge in print to any shareholder who requests it. Request for copies should be addressed to the Secretary at mailing address 2000 W. Sam Houston Parkway South, Suite 2000, Houston, TX 77042.

ITEM 11.  Executive Compensation

For information concerning Item 11, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 12.  Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

For information concerning the security ownership of certain beneficial owners and management, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 13.  Certain Relationships and Related Transactions and Director Independence

For information concerning Item 13, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

ITEM 14.  Principal Accountant Fees and Services

For information concerning Item 14, see the definitive proxy statement of Callon relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which will be filed with the Securities and Exchange Commission and is incorporated herein by reference.

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PART IV.

ITEM 15.  Exhibits

The following is an index to the financial statements and financial statement schedules that are filed in Part II, Item 8 of this report on Form 10-K.

			Incorporated by reference (File No. 001-14039, unless otherwise indicated)
Exhibit Number		Description	Form	Exhibit	Filing Date
2.1		Purchase and Sale Agreement, dated May 23, 2018, between Cimarex Energy Co, Prize Energy Resources, Inc., and Magnum Hunter Production, Inc. and Callon Petroleum Operating Company	8-K	2.1	05/24/2018
2.2	(d)	Purchase and Sale Agreement between Callon Petroleum Operating Company and Sequitur Permian, LLC dated April 8, 2019	8-K	2.1	06/13/2019
2.3	(d)	Agreement and Plan of Merger, dated as of July 14, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc.	8-K	2.1	07/15/2019
2.4		Amendment No. 1 to Agreement and Plan of Merger, dated August 19, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc.	10-Q	2.2	11/05/2019
2.5		Amendment No. 2 to Agreement and Plan of Merger, dated November 13, 2019, by and between Callon Petroleum Company and Carrizo Oil & Gas, Inc.	8-K	2.1	11/14/2019
3.1		Certificate of Incorporation of the Company, as amended through May 12, 2016	10-Q	3.1	11/03/2016
3.2		Certificate of Amendment to the Certificate of Incorporation of Callon, effective December 20, 2019	8-K	3.1	12/20/2019
3.3		Amended and Restated Bylaws of the Company	10-K	3.2	02/27/2019
4.1		Specimen Common Stock Certificate	10-K	4.1	02/28/2018
4.2	(a)	Description of Common Stock
4.3		Indenture of 6.125% Senior Notes Due 2024, dated as of October 3, 2016, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee	8-K	4.1	10/04/2016
4.4		First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee	8-K	4.3	12/20/2019
4.5		Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated October 3, 2016, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto	8-K	4.2	10/04/2016
4.6		Registration Rights Agreement of 6.125% Senior Notes Due 2024, dated May 24, 2017, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto	8-K	4.1	05/24/2017
4.7		Indenture of 6.375% Senior Notes Due 2026, dated as of June 7, 2018, among Callon Petroleum Company, the Guarantors party thereto and U.S. Bank National Association, as Trustee	8-K	4.1	06/07/2018
4.8		First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and U.S. Bank National Association, as trustee	8-K	4.4	12/20/2019
4.9		Registration Rights Agreement of 6.375% Senior Notes Due 2026, dated June 7, 2018, among Callon Petroleum Company, Callon Petroleum Operating Company and J.P. Morgan Securities LLC, as representative of the Initial Purchasers named on Annex E thereto	8-K	4.2	06/07/2018
4.10		Indenture, dated May 28, 2008, among Carrizo Oil & Gas, Inc., the subsidiaries named therein and Wells Fargo Bank, National Association, as trustee	8-K(File No. 000-29187-87)	4.1	05/28/2008
4.11		Sixteenth Supplemental Indenture, dated April 28, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K(File No. 000-29187-87)	4.2	04/28/2015
4.12		Eighteenth Supplemental Indenture, dated May 20, 2015, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K(File No. 000-29187-87)	4.2	05/22/2015
4.13		Twentieth Supplemental Indenture, dated July 14, 2017, among Carrizo Oil & Gas, Inc., the subsidiary guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K(File No. 000-29187-87)	4.2	07/14/2017
4.14		Twenty-First Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K	4.1	12/20/2019
4.15		Twenty-Second Supplemental Indenture, dated December 20, 2019, among Callon, the Guarantors named therein and Wells Fargo Bank, National Association, as trustee	8-K	4.2	12/20/2019
4.16		Warrant Agreement, dated as of December 20, 2019, between Callon and American Stock Transfer And Trust Company, LLC, as warrant agent	8-K	4.5	12/20/2019
10.1	(d)	Credit Agreement, dated December 20, 2019, among Callon, JPMorgan Chase Bank, National Association, as administrative agent, and the lenders party thereto	8-K	10.1	12/20/2019
10.2	(b)	Callon Petroleum Company 2011 Omnibus Incentive Plan	DEF 14A	A	03/21/2011
10.3	(b)	Form of Callon Petroleum Company Restricted Stock Unit Award Agreement, adopted on March 12, 2015	10-K	10.16	03/03/2016
10.4	(b)	First Amendment to the Callon Petroleum Company 2011 Omnibus Incentive Plan	10-Q	10.1	11/05/2015

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10.5		Amended and Restated Deferred Compensation Plan for Outside Directors - Callon Petroleum Company, dated as of May 10, 2017 and effective as of May 1, 2017	10-K	10.11	02/28/2018
10.6	(b)	Callon Petroleum Company 2018 Omnibus Incentive Plan	DEF 14A	A	03/23/2018
10.7	(a)	Amended and Restated 2018 Omnibus Incentive Plan
10.8	(b)	Form of Callon Petroleum Company Director Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan	10-Q	10.4	08/07/2018
10.9	(b)	Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan	10-Q	10.5	08/07/2018
10.10	(b)	Form of Callon Petroleum Company Employee Cash-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan	10-Q	10.6	08/07/2018
10.11	(b)	Form of Callon Petroleum Company Employee Stock-Settleable Performance Share Award Agreement, adopted on May 10, 2018 under the 2018 Omnibus Incentive Plan	10-Q	10.7	08/07/2018
10.12	(b)	Form of Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Callon Petroleum Company and its executive officers	10-K	10.17	02/27/2019
10.13	(b)	Change in Control Severance Compensation Agreement, dated as of January 1, 2019, by and between Joseph C. Gatto, Jr., and Callon Petroleum Company	10-K	10.18	02/27/2019
10.14	(b)	Carrizo Oil & Gas, Inc. Change in Control Severance Plan effective February 14, 2019	10-K(File No. 000-29187-87)	10.15	03/01/2019
10.15		Separation Agreement, dated January 2, 2019, by and between Gary A. Newberry and Callon Petroleum Company	10-K	10.19	02/27/2019
10.16		Separation Agreement, dated March 13, 2019, by and between Jerry A. Weant and Callon Petroleum Company	10-Q	10.1	05/07/2019
10.17	(b)	Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.20	02/27/2019
10.18	(b)	Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.21	02/27/2019
10.19	(b)	Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.22	02/27/2019
10.20	(b)	Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2019 under the 2018 Omnibus Incentive Plan	10-K	10.23	02/27/2019
10.21	(b)	2017 Incentive Plan of Carrizo Oil &Gas, Inc.	8-K(File No. 000-29187-87)	10.1	05/16/2019
10.22	(a)	Form of Callon Petroleum Company Employee Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan
10.23	(a)	Form of Callon Petroleum Officer Cash-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan
10.24	(a)	Form of Callon Petroleum Company Officer Stock-Settleable Performance Share Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan
10.25	(a)	Form of Callon Petroleum Company Officer Restricted Stock Unit Award Agreement, adopted on January 31, 2020 under the Amended & Restated 2018 Omnibus Incentive Plan
21.1	(a)	Subsidiaries of the Company
23.1	(a)	Consent of Grant Thornton LLP
23.2	(a)	Consent of DeGolyer and MacNaughton, Inc.
23.3	(a)	Consent of Ryder Scott Company, L.P.
31.1	(a)	Certification of Chief Executive Officer pursuant to Rule 13(a)-14(a)
31.2	(a)	Certification of Chief Financial Officer pursuant to Rule 13(a)-14(a)
32.1	(c)	Section 1350 Certifications of Chief Executive and Financial Officers pursuant to Rule 13(a)-14(b)
99.1	(a)	Reserve Report Summary prepared by DeGolyer and MacNaughton, Inc. as of December 31, 2019
99.2	(a)	Reserve Report Summary prepared by Ryder Scott Company, L.P. as of December 31, 2019
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 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

106

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.

(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.

107

ITEM 16. Form 10-K Summary

Not applicable.

108

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/ James P. Ulm, II	Date:	February 28, 2020
	By: James P. Ulm, II
	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 28, 2020
	Joseph C. Gatto, Jr. (principal executive officer)
	/s/ James P. Ulm, II	Date:	February 28, 2020
	James P. Ulm, II (principal financial officer)
	/s/ Gregory F. Conaway	Date:	February 28, 2020
	Gregory F. Conaway (principal accounting officer)
	/s/ L. Richard Flury	Date:	February 28, 2020
	L. Richard Flury (chairman of the board of directors)
	/s/ Frances Aldrich Sevilla-Sacasa	Date:	February 28, 2020
	Frances Aldrich Sevilla-Sacasa (director)
	/s/ Matthew R. Bob	Date:	February 28, 2020
	Matthew R. Bob (director)
	/s/ Barbara J. Faulkenberry	Date:	February 28, 2020
	Barbara J. Faulkenberry (director)
	/s/ Michael L. Finch	Date:	February 28, 2020
	Michael L. Finch (director)
	/s/ S.P. Johnson IV	Date:	February 28, 2020
	S.P. Johnson IV (director)
	/s/ Larry D. McVay	Date:	February 28, 2020
	Larry D. McVay (director)
	/s/ Anthony J. Nocchiero	Date:	February 28, 2020
	Anthony J. Nocchiero (director)
	/s/ James M. Trimble	Date:	February 28, 2020
	James M. Trimble (director)
	/s/ Steven A. Webster	Date:	February 28, 2020
	Steven A. Webster (director)

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EX-4.2

Exhibit 4.2

DESCRIPTION OF COMMON STOCK

Throughout this exhibit, references to “we,” “our,” and “us” refer to Callon Petroleum Company. The following summary of terms of our common stock, par value $0.01 per share (the “common stock”), is based upon our certificate of incorporation (as amended, our “Certificate of Incorporation”) and amended and restated bylaws (our “Bylaws”). This summary is not complete and is subject to, and qualified in its entirety by reference to, our Certificate of Incorporation and our Bylaws. For a complete description of the terms and provisions of the common stock, refer to our Certificate of Incorporation and our Bylaws. We encourage you to read these documents and the applicable portions of the Delaware General Corporation Law (the “DGCL”) carefully.

Common Stock

We are currently authorized to issue up to 525,000,000 shares of common stock. Holders of common stock are entitled to cast one vote for each share held of record on each matter submitted to a vote of shareholders. There is no cumulative voting for election of directors. Subject to the prior rights of any series of preferred stock that may from time to time be outstanding, if any, holders of common stock are entitled to receive ratably dividends when, as and if declared by our board of directors out of funds legally available for such purpose and, upon our liquidation, dissolution or winding up, are entitled to share ratably in all assets remaining after payment of liabilities and payment of accrued dividends and liquidation preferences on the preferred stock, if any. There are no redemption or sinking fund provisions that are applicable to the common stock. Subject only to the requirements of the DGCL, our board of directors may issue shares of common stock without shareholder approval, at any time and from time to time, to such persons and for such consideration as our board of directors deems appropriate. Holders of our common stock have no preemptive rights and have no rights to convert their common stock into any other securities.

Preferred Stock

We are authorized to issue up to 2,500,000 shares of preferred stock, par value $0.01 per share. As of February 27, 2020, there are no shares of preferred stock outstanding. Shares of preferred stock may be issued from time to time in one or more series as our board of directors may from time to time determine, each of said series to be distinctively designated. The voting powers, preferences and relative, participating, optional and other special rights, and the qualifications, limitations or restrictions thereof, if any, of each such series of preferred stock may differ from those of any and all other series of preferred stock at any time outstanding, and, subject to certain limitations set forth in our Certificate of Incorporation and the DGCL, our board of directors may fix or alter, by resolution or resolutions, the designation, number, voting powers, preferences and relative, participating, optional and other special rights, and qualifications, limitations and restrictions thereof, of each such series of preferred stock.

The issuance of any such preferred stock could adversely affect the rights of the holders of common stock and therefore, reduce the value of the common stock. The ability of our board of directors to issue preferred stock could discourage, delay, or prevent a takeover of us.

Anti-Takeover Effects of Provisions of Our Certificate of Incorporation and Our Bylaws

Some provisions of our Certificate of Incorporation and our Bylaws contain provisions that could make it more difficult to acquire us by means of a merger, tender offer, proxy contest or otherwise, or to remove our incumbent officers and directors. These provisions, summarized below, are expected to discourage coercive takeover practices and inadequate takeover bids. These provisions are also designed to encourage persons seeking to acquire control of us to first negotiate with our board of directors. We believe that the benefits of increased protection of our potential ability to negotiate with the proponent of an unfriendly or unsolicited proposal to acquire or restructure us outweigh the disadvantages of discouraging such proposals because negotiation of such proposals could result in an improvement of their terms.

Preferred Stock. Our Certificate of Incorporation permits our board of directors to authorize and issue one or more series of preferred stock, which may render more difficult or discourage an attempt to change control of us by means of a merger, tender offer, proxy contest or otherwise. For example, if in the due exercise of its fiduciary obligations, our board of directors were to determine that a takeover proposal is not in our best interest, it could cause shares of preferred stock to be issued without shareholder approval in one or more private offerings or other transactions that might dilute the voting or other rights of the proposed acquirer or insurgent shareholder or shareholder group.

Staggered Board of Directors. Our Certificate of Incorporation and our Bylaws divide our board of directors into three classes, as nearly equal in number as possible, serving staggered three-year terms. Our Certificate of Incorporation and our Bylaws also provide that the classified board provision may not be amended without the affirmative vote of the holders of 80% or more

of the voting power of our capital stock. The classification of our board of directors has the effect of requiring at least two annual shareholder meetings, instead of one, to effect a change in control of our board of directors, unless our Certificate of Incorporation and our Bylaws are amended.

Shareholder Meetings. Our Bylaws provide that a special meeting of shareholders may be called only by the chairman of our board of directors, our chief executive officer or president or by our board of directors or at the request of shareholders owning 80% or more of the entire capital stock issued and outstanding and entitled to vote.

Requirements for Advance Notification of Shareholder Nominations. Our Certificate of Incorporation and our Bylaws establish advance notice procedures with respect to shareholder nomination of candidates for election as directors, other than nominations made by or at the direction of our board of directors.

Shareholder Action By Written Consent. Our Certificate of Incorporation and our Bylaws provide that, except as may otherwise be provided with respect to the rights of the holders of preferred stock, no action that is required or permitted to be taken by our shareholders at any annual or special meeting may be effected by written consent of shareholders in lieu of a meeting of shareholders, unless the action to be effected is approved by the written consent of all of the shareholders entitled to vote thereon. This provision, which may not be amended except by the affirmative vote of holders of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class, makes it difficult for shareholders to initiate or effect an action by written consent that is opposed by our board of directors.

Amendment of Our Bylaws. Under Delaware law, the power to make, alter or repeal bylaws is conferred upon a corporation’s shareholders. A corporation may, however, in its certificate of incorporation also confer upon its board of directors the power to make, alter or repeal its bylaws. Our Certificate of Incorporation and our Bylaws grant our board of directors the power to make, alter or repeal our Bylaws at any regular or special meeting of our board of directors. By majority vote, our shareholders may make, alter or repeal our Bylaws but provisions of our Bylaws relating to shareholder meetings, directors and amendment of our Bylaws may only be amended by holders of at least 80% of the voting power of all then outstanding shares of capital stock entitled to vote generally in the election of directors, voting together as a single class.

The provisions of our Certificate of Incorporation and our Bylaws could have the effect of discouraging others from attempting hostile takeovers and, as a consequence, they may also inhibit temporary fluctuations in the market price of the common stock that often result from actual or rumored hostile takeover attempts. These provisions may also have the effect of preventing changes in our management. It is possible that these provisions could make it more difficult to accomplish transactions that shareholders may otherwise deem to be in their best interests.

Forum Selection. 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 behalf of us, (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 ours 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 ours arising pursuant to any provision of the DGCL, our Certificate of Incorporation or our 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 ours governed by the internal affairs doctrine, or (v) any action or proceeding as to which the DGCL confers jurisdiction on the Delaware Court of Chancery shall be the Delaware Court of Chancery or, if and only if the Delaware Court of Chancery lacks subject matter jurisdiction, any state court located within 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 of 1933, as amended, or the Securities Exchange Act of 1934, as amended. 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, shareholders would not be deemed to have waived our compliance with federal securities laws and the rules and regulations thereunder.

Delaware Anti-Takeover Statute

We are a Delaware corporation and are subject to Section 203 of the DGCL (“Section 203”). In general, Section 203 prevents us from engaging in a business combination with an “interested stockholder” (generally, a person owning 15% or more of our outstanding voting stock) for three years following the time that person becomes an interested stockholder unless either:

2

• before that person became an interested stockholder, our board of directors approved either the business combination or the transaction that resulted in the that person becoming an interested stockholder;

• upon completion of the transaction that resulted in that person becoming an interested stockholder, that person owned at least 85% of our voting stock outstanding at the time the transaction began (excluding stock held by directors who are also officers and by employee stock plans that do not provide employees with the right to determine confidentially whether shares held subject to the plan will be tendered in a tender or exchange offer); or

• after the transaction in which that person became an interested stockholder, the business combination is approved by our board of directors and authorized at a shareholder meeting by the affirmative vote of at least two-thirds of the outstanding voting stock not owned by the interested stockholder.

Under Section 203, these restrictions also do not apply to certain business combinations proposed by an interested stockholder following the disclosure of an extraordinary transaction with a person who was not an interested stockholder during the previous three years or who became an interested stockholder with the approval of a majority of our directors. This exception generally applies only if the extraordinary transaction is approved or not opposed by a majority of our directors who were directors before any person became an interested stockholder in the previous three years.

3

EX-10.7

Exhibit 10.7

CALLON PETROLEUM COMPANY

AMENDED AND RESTATED 2018 OMNIBUS INCENTIVE PLAN

1. Plan. This Callon Petroleum Company Amended and Restated 2018 Omnibus Incentive Plan (this “Plan”), as originally established effective as of May 10, 2018 (the “Original Effective Date”), was adopted by Callon Petroleum Company to reward and provide incentives to certain employees, independent contractors and directors by enabling them to acquire awards from the Company, including Awards related to shares of common stock of Callon Petroleum Company. The Plan is now amended and restated, effective as of immediately following the Closing (as defined in the Merger Agreement) to reflect the Company’s assumption of shares available for issuance under the Amended and Restated 2017 Incentive Plan of Carrizo Oil & Gas, Inc. in connection with the Merger (as defined below) (the “Assumed Shares”).

2. Definitions. As used herein, the terms set forth below shall have the following respective meanings:

“Affiliate” has the meaning ascribed to such term in Rule 12b-2 of the General Rules and Regulations of the Exchange Act.

“Award” means the grant of any Option, SAR, Stock Award, Cash Award or Performance Award whether granted singly, in combination or in tandem, to a Participant pursuant to such applicable terms, conditions and limitations as the Committee may establish in order to fulfill the objectives of this Plan.

“Award Agreement” means the document (in written or electronic form) setting forth the terms, conditions and limitations applicable to an Award. Such agreement shall be written except that the Committee may, in its discretion, require or allow that the Participant electronically execute or accept such Award Agreement.

“Board” means the Board of Directors of the Company. “Cash Award” means an Award denominated in cash.

“Change in Control” means the occurrence of one or more of the following:

(a) Change in Ownership. A change in ownership of the Company occurs on the date that any Person, other than (1) the Company or any of its Subsidiaries, (2) a trustee or other fiduciary holding securities under an employee benefit plan of the Company or any of its Affiliates, (3) an underwriter temporarily holding stock pursuant to an offering of such stock, or (4) a corporation owned, directly or indirectly, by the stockholders of the Company in substantially the same proportions as their ownership of the Company’s stock (each of (1) through (4) an “Exempt Person”), acquires ownership of the Company’s stock that, together with stock held by such Person, constitutes more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock. However, if any Person is considered to own already more than fifty percent (50%) of the total fair market value or total voting power of the Company’s Voting Stock, the acquisition of additional stock by the same Person is not considered

to be a Change in Control. In addition, if any Person has effective control of the Company through ownership of thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, as discussed in paragraph (b) below, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this paragraph (a); or

(b) Change in Effective Control. Even though the Company may not have undergone a change in ownership under paragraph (a) above, a change in the effective control of the Company occurs on either of the following dates: (1) the date that any Person (other than an Exempt Person) acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) ownership of the Company’s stock possessing thirty percent (30%) or more of the total voting power of the Company’s Voting Stock. However, if any Person owns thirty percent (30%) or more of the total voting power of the Company’s Voting Stock, the acquisition of additional control of the Company by the same Person is not considered to cause a Change in Control pursuant to this subparagraph (b)(1); or

(2) the date that during any period of three consecutive years, individuals who at the beginning of such period were members of the Board cease for any reason to constitute at least a majority thereof unless the election, or the nomination for election by the Company’s stockholders, of each new director was approved by a vote of at least a majority of the directors then still in office who were directors at the beginning of such period or whose election or nomination was previously so approved; provided, however, that any such director shall not be considered to be approved by the Board if his or her initial assumption of office occurs as a result of an actual or threatened solicitation of proxies or consents by or on behalf of a Person other than the Board; or

(c) Change in Ownership of Substantial Portion of Assets. A change in the ownership of a substantial portion of the Company’s assets occurs on the date that a Person acquires (or has acquired during the 12-month period ending on the date of the most recent acquisition by such Person) assets of the Company that have a total gross fair market value equal to at least forty percent (40%) of the total gross fair market value of all of the Company’s assets immediately before such acquisition or acquisitions. However, there is no Change in Control when there is such a transfer to an entity that is controlled by the stockholders of the Company immediately after the transfer, through a transfer to (1) a stockholder of the Company (immediately before the asset transfer) in exchange for or with respect to the Common Stock; (2) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned, directly or indirectly, by the Company; (3) a Person that owns directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock; or (4) an entity, at least fifty percent (50%) of the total value or voting power of the stock of which is owned by a Person that owns, directly or indirectly, at least fifty percent (50%) of the total value or voting power of the Company’s outstanding Voting Stock.

Notwithstanding the foregoing, no Change in Control payment event shall be deemed to have occurred with respect to an Award that is subject to Section 409A of the Code unless such event constitutes a permissible payment event specified in Section 409A of the Code and the Treasury regulations promulgated thereunder.

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“Code” means the Internal Revenue Code of 1986, as amended from time to time.

“Committee” means (i) the Compensation Committee of the Board or (ii) such other committee of the Board as is designated by the Board to administer this Plan or (iii) to the extent contemplated hereby, the Board.

“Common Stock” means the common stock, par value $.01 per share, of the Company. “Company” means Callon Petroleum Company, a Delaware corporation.

“Director” means an individual serving as a member of the Board.

“Dividend Equivalents” means, with respect to the shares of Common Stock subject to a Stock Award other than Restricted Stock, an amount equal to all dividends and other distributions (or the economic equivalent thereof) that are payable to stockholders of record during the Restriction Period on a like number of shares of Common Stock.

“Employee” means an employee of the Company or any of its Subsidiaries.

“Exchange Act” means the Securities Exchange Act of 1934, as amended from time to time.

“Fair Market Value” of a share of Common Stock means, as of a particular date, (i)(A) if the shares of Common Stock are listed or on a national securities exchange (including the NASDAQ Global Select Market), the closing price per share of the Common Stock on the consolidated transaction reporting system for the principal national securities exchange on which shares of Common Stock are listed on that date, or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported, or, at the discretion of the Committee, the price prevailing on the exchange at the time of exercise or other relevant event (as determined under procedures established by the Committee) including the average of the closing bid and asked price on that date, (B) if the shares of Common Stock are not so listed but are listed or quoted on another securities exchange or market, the closing price per share of Common Stock reported on the principal securities exchange or market on which the shares of Common Stock are traded (as determined by the Committee), or, if there shall have been no such sale so reported on that date, on the last preceding date on which such a sale was so reported or, at the discretion of the Committee, the price prevailing on such principal securities exchange or market at the time of exercise or other relevant event, including the average of the closing bid and asked price on that date, or, if there are no quotations available for such date, on the last preceding date on which such quotations shall be available, (C) if the shares of Common Stock are not publicly traded, the most recent value determined by an independent appraiser appointed by the Company for such purpose, or (D) if none of (A)-(C) are applicable, the fair market value of a share of Common Stock as determined in good faith by the Committee; or (ii) if applicable, the price per share as determined in accordance with the procedures of a third party administrator retained by the Company to administer this Plan and as approved by the Committee.

“Incentive Option” means an Option that is intended to comply with the requirements set forth in Section 422 of the Code.

“Independent Contractor” means an individual providing services to the Company or any of its Subsidiaries, who is not an Employee. An Independent Contractor can include an individual who is serving as a Non-employee Director.

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“Merger” means the merger of Carrizo with and into the Company effective as of December 20, 2019, in accordance with the terms of the Merger Agreement.

“Merger Agreement” means the Agreement and Plan of Merger, dated July 14, 2019, by and among the Company and Carrizo.

“Non-employee Director” means a Director who is not an Employee. A Non-employee Director may, in the discretion of the Committee, receive an Award both in the capacity as a Non-employee Director and Independent Contractor.

“Nonqualified Stock Option” means an Option that is not an Incentive Option.

“Option” means a right to purchase a specified number of shares of Common Stock at a specified price, which is either an Incentive Option or a Nonqualified Stock Option.

“Participant” means an Employee, Non-employee Director or Independent Contractor to whom an Award has been made under this Plan.

“Performance Award” means an award made pursuant to this Plan to a Participant which is subject to the attainment of one or more Performance Goals.

“Performance Goal” means a standard established by the Committee, to determine in whole or in part whether a Performance Award shall be earned.

“Person” shall have the meaning ascribed to such term in Section 3(a)(9) of the Exchange Act and used in Sections 13(d) and 14(d) thereof, including a “group” as defined in Section 13(d) thereof.

“Prior Plan” means the Callon Petroleum Company 2011 Omnibus Incentive Plan, as thereafter amended.

“Restricted Stock” means any Common Stock that is restricted or subject to forfeiture provisions.

“Restricted Stock Unit” means a right to receive a share of Common Stock or the value thereof on such terms and conditions as may be established by the Committee. For the avoidance of doubt, such term includes phantom shares and phantom stock units.

“Restriction Period” means a period of time beginning as of the date upon which a Stock Award is made pursuant to this Plan and ending as of the date upon which the Common Stock subject to such Stock Award is deliverable or no longer restricted or such Stock Award is no longer subject to forfeiture provisions.

“Rule 16b-3” means Rule 16b-3 promulgated under the Exchange Act, or any successor rule.

“SAR” means a right to receive a payment, in cash or Common Stock, equal to the excess of the Fair Market Value or other specified valuation of a specified number of shares of Common Stock on the date the right is exercised over a specified strike price, in each case, as determined by the Committee.

“Stock Award” means an award in the form of shares of Common Stock or units denominated in shares of Common Stock, including Restricted Stock and Restricted Stock Units. For the avoidance of doubt,

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a Stock Award does not include an Option or SAR.

“Subsidiary” means (i) in the case of a corporation, any corporation of which the Company directly or indirectly owns shares representing more than 50% of the combined voting power of the shares of all classes or series of capital stock of such corporation which have the right to vote generally on matters submitted to a vote of the stockholders of such corporation and (ii) in the case of a partnership or other business entity not organized as a corporation, any such business entity of which the Company directly or indirectly owns more than 50% of the voting, capital or profits interests (whether in the form of partnership interests, membership interests or otherwise).

“Voting Stock” shall mean stock of any class or kind having the power to vote generally for the election of Directors.

3. Eligibility. All Employees, Non-employee Directors and Independent Contractors are eligible for Awards under this Plan in the sole discretion of the Committee.

4. Common Stock Available for Awards. Subject to the provisions of Section 14 hereof, there shall be available for Awards under this Plan granted wholly or partly in Common Stock (including rights or Options that may be exercised for or settled in Common Stock) an aggregate of [] shares of Common Stock (“Share Reserve”), of which [ ] are Assumed Shares, plus the shares remaining available for awards under the Prior Plan as of the Original Effective Date, all of which shall be available for Incentive Options. Notwithstanding anything herein to the contrary, in accordance with the New York Stock Exchange Listed Company Manual and interpretative guidance thereunder (including Rule 303A.08), the Assumed Shares shall not be available for grant (i) beyond the period when such Assumed Shares would have been available for grant under the Amended and Restated 2017 Incentive Plan of Carrizo Oil & Gas, Inc., absent the Merger, but in no event beyond the ten year anniversary of the Original Effective Date, nor (ii) for Awards under this Plan to individuals who were employed by the Company or a Subsidiary thereof as of immediately prior to the Closing. The number of shares of Common Stock that are the subject of Awards under this Plan or the Prior Plan, that are forfeited or terminated, expire unexercised, are settled in cash in lieu of Common Stock or are exchanged for Awards that do not involve Common Stock, shall again immediately become available for additional Awards hereunder. Notwithstanding the foregoing, the following shares of Common Stock may not again be made available for issuance as Awards under this Plan: (i) shares of Common Stock not issued or delivered as a result of the net settlement of a stock-settled SAR or Option, (ii) shares of Common Stock used to pay the exercise price or withholding taxes related to an outstanding Option or SAR, or (iii) shares of Common Stock

repurchased on the open market with the proceeds of the option exercise price. The Board and the appropriate officers of the Company shall from time to time take whatever actions are necessary to file any required documents with governmental authorities, stock exchanges and transaction reporting systems to ensure that shares of Common Stock are available for issuance pursuant to Awards.

5. Administration.

(a) Except as otherwise provided in this Plan with respect to actions or determinations by the Board, this Plan shall be administered by the Committee. To the extent required in order for Awards to be exempt from Section 16 of the Exchange Act by virtue of the

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provisions of Rule 16b-3, (i) the Committee shall consist of at least two members of the Board who meet the requirements of the definition of “Non- employee Director” set forth in Rule 16b-3 (b)(3)(i) promulgated under the Exchange Act or (ii) Awards may be granted by, and this Plan may be administered by, the Board.

(b) Subject to the provisions hereof, the Committee shall have full and exclusive power and authority to administer this Plan and to take all actions that are specifically contemplated hereby or are necessary or appropriate in connection with the administration hereof. The Committee shall also have full and exclusive power to interpret this Plan and to adopt such rules, regulations and guidelines for carrying out this Plan as it may deem necessary or proper. The Committee may, in its discretion, provide for the extension of the exercisability of an Award, accelerate the vesting or exercisability of an Award, eliminate or make less restrictive any restrictions contained in an Award, waive any restriction or other provision of this Plan or an Award or otherwise amend or modify an Award in any manner that is either (i) not adverse to the Participant to whom such Award was granted or (ii) consented to by such Participant. The Committee may make an Award to an individual who it expects to become an Employee, Non-employee Director or Independent Contractor of the Company or any of its Subsidiaries within the next six months, with such award being subject to the individual actually becoming an Employee, Non-employee Director or Independent Contractor, as applicable, within such time period, and subject to such other terms and conditions as may be established by the Committee. The Committee may correct any defect or supply any omission or reconcile any inconsistency in this Plan or in any Award in the manner and to the extent the Committee deems necessary or desirable to further the purposes of this Plan. Any decision of the Committee in the interpretation and administration of this Plan shall lie within its sole and absolute discretion and shall be final, conclusive and binding on all parties concerned. The Board shall have the same powers as the Committee with respect to Awards granted to Non-employee Directors.

(c) Notwithstanding the foregoing, except in connection with a transaction involving the Company or its capitalization (as provided in Section 14), the terms of outstanding Awards may not be amended without approval of the stockholders of the Company to (i) reduce the exercise price of outstanding Options or SARs or (ii) cancel, exchange, substitute, buyout or surrender outstanding Options or SARs in exchange for cash or other Awards when the exercise price per share of the original Options or SARs exceeds the Fair Market Value of one share of Common Stock, (iii) take any other action with respect to an Option or SAR that would be treated as a repricing under the rules and regulations of the principal national securities exchange on which the shares of Common Stock are listed or (iv) permit the grant of any Options or SARs that contains a so-called “reload” feature under which additional Options, SARs or other Awards are granted automatically to the Participant upon exercise of the original Option or SAR.

(d) No member of the Committee or the Board or officer of the Company to whom the Committee has delegated authority in accordance with the provisions of Section 6 of this Plan shall be liable for anything done or omitted to be done by him or her, by any member of the Committee or by any officer of the Company in connection with the performance of any duties under this Plan, except for his or her own willful misconduct or as expressly provided by statute.

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6. Delegation of Authority. To the extent allowed by applicable law, the Committee may delegate to the Chief Executive Officer, to other senior officers of the Company or to other committees of the Board its duties under this Plan pursuant to such conditions or limitations as the Committee may establish, except that the Committee may not delegate to any person the authority to grant Awards to, or take other action with respect to, Participants who are subject to Section 16 of the Exchange Act.

7. Employee and Independent Contractor Awards. The Committee shall determine the type or types of Awards to be made under this Plan and shall designate from time to time the Employees and Independent Contractors who are to be the recipients of such Awards. Each Award may be embodied in an Award Agreement, which shall contain such terms, conditions and limitations as shall be determined by the Committee in its sole discretion, including any treatment upon a Change in Control, and shall be accepted by the Participant to whom the Award is made. Awards may consist of those listed in this Section 7 and may be granted singly, in combination or in tandem. Awards may also be made in combination or in tandem with, in replacement of, or as alternatives to, grants or rights under this Plan or any other employee plan of the Company or any of its Subsidiaries, including the plan of any acquired entity. All or part of an Award may be subject to conditions established by the Committee, which may include, but are not limited to, continuous service with the Company, its Affiliates and Subsidiaries, or achievement of specific performance or business objectives. Upon the termination of service with the Company, its Affiliates and Subsidiaries of a Participant, any unexercised, deferred, unvested or unpaid Awards shall

(a) Stock Option. An Award may be in the form of an Option. An Option awarded pursuant to this Plan may consist of an Incentive Option or a Nonqualified Option. The price at which a share of Common Stock may be purchased upon the exercise of an Option shall be not less than the Fair Market Value of the Common Stock on the date of grant. Subject to the foregoing provisions, the terms, conditions and limitations applicable to any Options awarded pursuant to this Plan, including the term of any Options and the date or dates upon which they become exercisable,

shall be determined by the Committee. Only Employees may be granted Incentive Options. The term of Options shall not exceed ten years from the date of grant. Any Option (i) that remains outstanding as of the last day of its term, (ii) has an exercise price per share that is less than the Fair Market Value of a share of Common Stock as of such day and (iii) whose exercise is prohibited as of such day pursuant to the operation of the Company’s insider trading policy, shall be automatically exercised (without any action on the part of the Participant holding such Option) by (A) foregoing the delivery of shares of Common Stock otherwise deliverable upon the exercise of the Option pursuant to Section 10 in an amount sufficient to pay the exercise price of the Option and (B) satisfying tax withholding obligations pursuant to Section 11 by withholding from the shares of Common Stock otherwise deliverable upon the exercise of the Option using the minimum tax rate applicable to the Participant. Each Participant who receives Options pursuant to the Plan shall be deemed to have accepted this automatic exercise provision as a condition of receiving the Option.

(b) Stock Appreciation Right. An Award may be in the form of a SAR. The per share strike price for a SAR shall be not less than the Fair Market Value of the Common Stock on

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the date on which the SAR is granted. The terms, conditions and limitations applicable to any SARs awarded pursuant to this Plan, including the term of any SARs, whether the SAR will be settled in cash or stock and the date or dates upon which they become exercisable, shall be determined by the Committee. The term of SARs shall not exceed ten years from the date of grant. Any SAR (i) that remains outstanding as of the last day of its term, (ii) has a strike price per share that is less than the Fair Market Value of a share of Common Stock as of such day and (iii) whose exercise is prohibited as of such day pursuant to the operation of the Company’s insider trading policy, shall be automatically exercised (without any action on the part of the Participant holding such SAR) and any tax withholding obligations will be satisfied pursuant to Section 11 by withholding from the cash or shares of Common Stock otherwise deliverable upon the exercise of the SAR using the minimum tax rate applicable to the Participant. Each Participant who receives SARs pursuant to the Plan shall be deemed to have accepted this automatic exercise provision as a condition of receiving the SAR.

(c) Stock Award. An Award may be in the form of a Stock Award. The terms, conditions and limitations applicable to any Stock Awards granted pursuant to this Plan shall be determined by the Committee.

(d) Cash Award. An Award may be in the form of a Cash Award. The terms, conditions and limitations applicable to any Cash Awards granted pursuant to this Plan shall be determined by the Committee.

(e) Performance Award. Without limiting the type or number of Awards that may be made under the other provisions of this Plan, an Award may be in the form of a Performance Award. A Performance Award shall be paid, vested or otherwise deliverable solely on account of the attainment of one or more Performance Goals,

either individually or in any combination, established by the Committee and specified in the award agreement.

Unless otherwise stated, such a Performance Goal need not be based upon an increase or positive result under a particular business criterion and could include, for example, maintaining the status quo or limiting economic losses (measured, in each case, by reference to specific business criteria). The amount of cash or shares payable or vested pursuant to Performance Awards may be adjusted upward or downward, either on a formula or discretionary basis or any combination, as the Committee determines. Subject to the foregoing provisions, the terms, conditions and limitations applicable to any Performance Awards made pursuant to this Plan shall be determined by the Committee.

8. Director Awards.

(a) The Board has the sole authority to grant Awards to Non-employee Directors from time to time in accordance with this Section 8. Such Awards may consist of the forms of Award described in Section 7, other than Incentive Options, and shall be granted subject to such terms and conditions as specified in Section 7.

(b) No Non-employee Director may be granted during any calendar year Awards having a fair value determined on the date of grant when added to all cash compensation paid to the Non-employee Director (in his capacity as Non-employee Director) during the same

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calendar year in excess of $1,000,000.

9. Payment of Awards.

(a) General. Payment of Awards may be made in the form of cash or Common Stock, or a combination thereof, and may include such restrictions as the Committee shall determine, including, in the case of Common Stock, restrictions on transfer and forfeiture provisions. If payment of an Award is made in the form of Restricted Stock, the right to receive such shares shall be evidenced by book entry registration or in such other manner as the Committee may determine. Any statement of ownership evidencing such Restricted Stock shall contain appropriate legends and restrictions that describe the terms and conditions of the restrictions applicable thereto.

(b) Dividends and Interest. In the discretion of the Committee, rights to dividends or Dividend Equivalents may be extended to and made part of any Stock Award or Performance Award, but such dividends or Dividend Equivalents shall be accrued and held by the Company and paid, without interest, within 10 days following the lapse of the restrictions on the Stock Award or Performance Award. For the avoidance of doubt, dividends and Dividend Equivalents will not, in any event, be payable until the restrictions on the underlying Stock Award or Performance Award have lapsed. In the event the Stock Award or Performance Award is forfeited, dividends and Dividend Equivalents paid with respect to such shares during the Restriction Period shall also be forfeited. No Dividend Equivalents may be paid in respect of an Award of Options or SARs.

10. Stock Option Exercise. The price at which shares of Common Stock may be purchased under an Option shall be paid in full at the time of exercise in cash or, if elected by the optionee, the optionee may purchase such shares by means of tendering Common Stock valued at Fair Market Value on the date of exercise, or any combination thereof. The Committee shall determine acceptable methods for Participants to tender Common Stock. The Committee may provide for procedures to permit the exercise or purchase of such Awards by foregoing the delivery of shares of Common Stock otherwise deliverable upon the exercise of the Option or by use of the proceeds to be received from the sale of Common Stock issuable pursuant to an Award.

11. Taxes. The Company shall have the right to deduct applicable taxes from any Award payment and withhold, at the time of delivery or vesting of cash or shares of Common Stock under this Plan, an appropriate amount of cash or number of shares of Common Stock or a combination thereof for payment of taxes required by law or to take such other action as may be necessary in the opinion of the Company to satisfy all obligations for withholding of such taxes. The Committee may also permit withholding to be satisfied by

(i)the transfer to the Company of shares of Common Stock theretofore owned by the holder of the Award or (ii) withholding from the shares otherwise deliverable under the Award, in either case with respect to which withholding is required, up to the maximum tax rate applicable to the Participant, as determined by the Committee. If shares of Common Stock are used to satisfy tax withholding, such shares shall be valued based on the Fair Market Value when the tax withholding is required to be made.

12. Amendment, Modification, Suspension or Termination. The Board may amend, modify, suspend

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or terminate this Plan for the purpose of meeting or addressing any changes in legal requirements or for any other purpose permitted by law, except that (i) no amendment or alteration that would adversely affect the rights of any Participant under any Award previously granted to such Participant shall be made without the consent of such Participant and (ii) no amendment or alteration shall be effective prior to its approval by the stockholders of the Company to the extent such approval is then required pursuant to Rule 16b-3 in order to preserve the applicability of any exemption provided by such rule to any Award then outstanding (unless the holder of such Award consents) or to the extent stockholder approval is otherwise required by applicable legal requirements.

13. Assignability. Unless otherwise determined by the Committee and provided in the Award Agreement, no Award or any other benefit under this Plan constituting a derivative security within the meaning of Rule 16a-1(c) under the Exchange Act shall be assignable or otherwise transferable except by will or the laws of descent and distribution or pursuant to a qualified domestic relations order in a form acceptable to the Committee. The Committee may prescribe and include in applicable Award Agreements other restrictions on transfer. Any attempted assignment of an Award or any other benefit under this Plan in violation of this Section 13 shall be null and void.

14. Adjustments.

(a) The existence of outstanding Awards shall not affect in any manner the right or power of the Company or its stockholders to make or authorize any or all adjustments, recapitalizations, reorganizations or other changes in the capital stock of the Company or its business or any merger or consolidation of the Company, or any issue of bonds, debentures, preferred or prior preference stock (whether or not such issue is prior to, on a parity with or junior to the Common Stock) or the dissolution or liquidation of the Company, or any sale or transfer of all or any part of its assets or business, or any other corporate act or proceeding of any kind, whether or not of a character similar to that of the acts or proceedings enumerated above.

(b) In the event of any subdivision or consolidation of outstanding shares of Common Stock, declaration of a dividend payable in shares of Common Stock or other stock split, the adoption by the Company of any plan of exchange affecting the Common Stock or any distribution to holders of Common Stock of securities or property (other than normal cash dividends or dividends payable in Common Stock), (i) the number of shares of Common Stock reserved under this Plan, (ii) the number of shares of Common Stock covered by Awards in the form of Common Stock or units denominated in Common Stock, (iii) the exercise or other price in respect of such Awards, and (iv) the appropriate Fair Market Value and other price determinations for such Awards shall each be proportionately adjusted by the Board to reflect such event; provided that such adjustments shall only be such as are necessary to maintain the proportionate interest of the holders of the Awards and preserve, without exceeding, the value of such Awards.

(c) In the event of a corporate merger, consolidation, acquisition of property or stock, separation, reorganization or liquidation, the Board may make such adjustments to outstanding Awards or other provisions for the disposition of outstanding Awards as it deems equitable, and shall be authorized, in its discretion, (i) to provide for the

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substitution of a new Award or other arrangement (which, if applicable, may be exercisable for such property or stock as the Board determines) for an outstanding Award or the assumption of an outstanding Award, regardless of whether in a transaction to which Section 424(a) of the Code applies, (ii) to provide, prior to the transaction, for the acceleration of the vesting and exercisability of, or lapse of restrictions with respect to, the outstanding Award and, if the transaction is a cash merger, to provide for the termination of any portion of the Award that remains unexercised at the time of such transaction or (iii) to provide for the acceleration of the vesting and exercisability of an outstanding Award and the cancellation thereof in exchange for such payment of such cash or property as shall be determined by the Board in its sole discretion, which for the avoidance of doubt in the case of Options or SARs (whether stock- or cash-settled) shall be the excess, if any, of the Fair Market Value of the shares of Common Stock subject to the Option or SAR on such date over the aggregate exercise price of such Award; provided, however, that no such adjustment shall increase the aggregate value of any outstanding Award. No adjustment or substitution pursuant to this Section 14 shall be made in a manner that results in noncompliance with Section 409A of the Code, to the extent applicable.

15. Restrictions. No Common Stock or other form of payment shall be issued with respect to any Award unless the Company shall be satisfied based on the advice of its counsel that such issuance will be in compliance with applicable federal and state securities laws. It is the intent of the Company that grants of Awards under this Plan comply with Rule 16b-3 with respect to persons subject to Section 16 of the Exchange Act unless otherwise provided herein or in an Award Agreement and that any ambiguities or inconsistencies in the construction of such an Award or this Plan be interpreted to give effect to such intention. Certificates evidencing shares of Common Stock delivered under this Plan (to the extent that such shares are so evidenced) may be subject to such stop transfer orders and other restrictions as the Committee may deem advisable under the rules, regulations and other requirements of the Securities and Exchange Commission, any securities exchange or transaction reporting system upon which the Common Stock is then listed or to which it is admitted for quotation and any applicable federal or state securities law. The Committee may cause a legend or legends to be placed upon such certificates (if any) to make appropriate reference to such restrictions. The Committee may also impose such restrictions, conditions or limitations as it determines appropriate as to the timing and manner of any resales by a Participant, other subsequent transfers by the Participant of any shares of Common Stock issued as a result of or under an Award, or the exercise of Options and SARs, including without limitation, restrictions under an insider trading policy.

16. Unfunded Plan. Insofar as it provides for Awards of cash, Common Stock or rights thereto, this Plan shall be unfunded. Although bookkeeping accounts may be established with respect to Participants who are entitled to cash, Common Stock or rights thereto under this Plan, any such accounts shall be used merely as a bookkeeping convenience. The Company shall not be required to segregate any assets that may at any time be represented by cash, Common Stock or rights thereto, nor shall this Plan be construed as providing for such segregation, nor shall the Company, the Board or the Committee be deemed to be a trustee of any cash, Common Stock or rights thereto to be granted under this Plan. Any liability or obligation of the Company to any Participant with respect to an Award of cash, Common Stock or rights thereto under this Plan shall be based solely upon any contractual obligations that may be created by this Plan and any

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Award Agreement, and no such liability or obligation of the Company shall be deemed to be secured by any pledge or other encumbrance on any property of the Company. Neither the Company nor the Board nor the Committee shall be required to give any security or bond for the performance of any obligation that may be created by this Plan.

17. Section 409A of the Code. All Awards under this Plan are intended either to be exempt from, or to comply with the requirements of Section 409A, and this Plan and all Awards shall be interpreted and operated in a manner consistent with that intention. Notwithstanding anything in this Plan to the contrary, if any Plan provision or Award under this Plan would result in the imposition of an applicable tax under Section 409A, that Plan provision or Award shall be reformed to avoid imposition of the applicable tax and no such action shall be deemed to adversely affect the Participant’s rights to an Award.

18. Governing Law. This Plan and all determinations made and actions taken pursuant hereto, to the extent not otherwise governed by mandatory provisions of the Code or the securities

laws of the United States, shall be governed by and construed in accordance with the laws of the State of Delaware.

19. Clawback. To the extent required by applicable law or any applicable securities exchange listing standards, or as otherwise determined by the Committee, Awards and amounts paid or payable pursuant to or with respect to Awards shall be subject to the provisions of any clawback policy implemented by the Company, which clawback policy may provide for forfeiture, repurchase or recoupment of Awards and amounts paid or payable pursuant to or with respect to Awards. Notwithstanding any provision of this Plan or any Award Agreement to the contrary, the Company reserves the right, without the consent of any Participant, to adopt any such clawback policies and procedures.

20. No Right to Employment or Continued Service. Nothing in this Plan or an Award Agreement shall interfere with or limit in any way the right of the Company or a Subsidiary to terminate any Participant’s employment or other service relationship at any time, nor confer upon any Participant any right to continue in the capacity in which he or she is employed or otherwise serves the Company or any Subsidiary. Further, nothing in this Plan or an Award Agreement constitutes any assurance or obligation of the Board to nominate any Non-employee Director for re-election by the Company’s stockholders.

21. Successors. All obligations of the Company under this Plan with respect to Awards granted hereunder shall be binding on any successor to the Company by merger, consolidation or otherwise.

22. Effectiveness. This Plan, was originally approved by the Board on March 21, 2018, and approved by the stockholders of the Company on May 10, 2018, and was thereafter amended and restated, effective as of immediately following the Closing. This Plan shall continue in effect for a term of ten years after the Original Effective Date, unless sooner terminated by action of the Board.    

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IN WITNESS WHEREOF, the parties hereto have caused this Agreement to be duly executed, as of the day and year first above written.

CALLON PETROLEUM COMPANY

By: /s/ Joseph C. Gatto, Jr.

Name: Joseph C. Gatto, Jr.

Title: President, Chief Executive Officer

Signature Page to Warrant Agreement

EX-10.23

Exhibit 10.22

2020 EMPLOYEE RESTRICTED STOCK UNIT AWARD AGREEMENT

(NON-OFFICER)

CALLON PETROLEUM COMPANY

AMENDED AND RESTATED 2018 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT (“Agreement”) is effective as of [•] (the “Grant Date”), by and between Callon Petroleum Company, a Delaware corporation (the “Company”), and ____________________ (the “Grantee”).

The Company has adopted the Amended and Restated Callon Petroleum Company 2018 Omnibus Incentive Plan, (the “Plan”), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee’s personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Restricted Stock Units. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive __________ shares of Common Stock of the Company, par value $.01 per share (“Restricted Stock Units”).

2.Vesting Schedule and Settlement.

Subject to the provisions of Section 3 hereof, the Restricted Stock Units shall vest in one-third increments (rounded up to the nearest whole number) on each of [DATE], [DATE] and [DATE] (each, a “Vesting Date”); provided that the Grantee remains in continuous employment with the Company through the applicable Vesting Date. For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.

As soon as practicable (but in no event later than thirty (30) days) following the occurrence of the Vesting Date or vesting pursuant to Section 3, the Company shall deliver to the Grantee or, as applicable, the Grantee’s legal representative, estate, beneficiary or heir, certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book entry form in the Grantee’s name in the stock register of the Company maintained by the Company’s transfer agent.

3.Termination of Employment; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee’s employment with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, “Disability” shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Company, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.

(b)Qualified Separation from Service. If the Grantee’s employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.  For purposes hereof, a “Qualified Separation from Service” is defined as a termination of Grantee’s employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, and (ii) Grantee has attained the age of fifty-five (55).

For purposes hereof, “Cause” is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Company, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee’s employment with the Company of any of the restrictive covenants set out in the Grantee’s employment agreement with the Company, if applicable, or (2) the material nonperformance of the Grantee’s duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee’s illness or incapacity); (vi) any breach of the Grantee's fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.

(c)Termination following a Change in Control. In the event of the Grantee’s termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.

(d)Company Equity Acceleration Benefits and Carrizo CIC Plan Inapplicable. Notwithstanding anything to the contrary contained herein, but subject to Section 4(c), the Carrizo Oil & Gas Inc. Change in Control Severance Plan (as may be amended from time to time) (the "Carrizo CIC Plan") and any other potential rights to equity acceleration benefits in connection with a termination of employment related to the merger of Carrizo Oil & Gas, Inc. with and into the Company (the "Other Acceleration Benefits") shall not apply to the Restricted Stock Units granted hereunder. As a condition of

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receiving this Award, Grantee hereby expressly acknowledges and agrees that, notwithstanding anything set forth in the Carrizo CIC Plan to the contrary, the Change in Control Benefits (as defined in the Carrizo CIC Plan), the Severance Benefits (as set forth in Section 3.02(c)(3) of the Carrizo CIC Plan) and the Other Acceleration Benefits shall not apply to the Restricted Stock Units granted hereunder, and hereby waives any right to any equity acceleration benefits provided for under the Carrizo CIC Plan or the Other Acceleration Benefits with respect to this award of Restricted Stock Units. In the event this Section 4(d) should be held by a court of competent jurisdiction to be unenforceable, this Agreement shall be terminated and of no further force or effect and all Restricted Stock Units (whether vested or unvested) shall be immediately forfeited to the Company without any consideration.

(e)Forfeiture. Upon termination of the Grantee’s employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Restricted Stock Units shall be immediately forfeited to the Company.

4.Clawback Policy. The Grantee hereby acknowledges and agrees that all rights with respect to the Restricted Stock Units are subject to the Company's Clawback Policy, as may be in effect from time to time. The Grantee further acknowledges and agrees that the Restricted Stock Units and amounts received with respect to the Restricted Stock Units are subject to recoupment pursuant to the terms of the Company Clawback Policy.

5.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.

6.Mandatory Withholding ofTaxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee’s tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance with the Company’s insider trading policies, authorizes the Company or the Company’s Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise payable or deliverable an amount of cash and/or

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number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.

7.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

8.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Ste. 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Ste. 2000

Houston, Texas 77042

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee’s address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee’s e‑mail address specified in the Company’s records or e-mail address provided by the Grantee to the Company’s Stock Plan Administrator.

9.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee’s employment at any time, with or without cause; subject, however, to the provisions of the Grantee’s employment agreement, if applicable.

10.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of

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any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

11.Construction. References in this Agreement to “this Agreement” and the words “herein,” “hereof,” “hereunder” and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

12.Code Section 409A. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a “specified employee” within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a “separation from service” (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee’s separation from service, (2) the date of the Grantee’s death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.

13.Excise Taxes. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a “disqualified individual” (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a “parachute payment” (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee’s “base amount” (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the

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Grantee’s base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.

14.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company’s Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

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EX-10.24

Exhibit 10.23

2020 PERFORMANCE SHARE AWARD AGREEMENT

(OFFICER - CASH DISTRIBUTION)

CALLON PETROLEUM COMPANY

AMENDED AND RESTATED 2018 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT ("Agreement") is effective as of [•] (the "Grant Date"), by and between Callon Petroleum Company, a Delaware corporation (the "Company"), and ____________________ (the "Grantee").

The Company has adopted the Amended and Restated Callon Petroleum Company 2018 Omnibus Incentive Plan (the "Plan"), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the performance shares provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee's personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Performance Shares.Pursuant to the Plan and subject further to the terms and conditions herein, the Company and Grantee enter into this Agreement pursuant to which the Grantee has a target of ________ performance shares (the "Target Award") where each performance share represents the right to receive the cash equivalent of the Fair Market Value of one share of Common Stock (the "Performance Shares"). The range of Performance Shares which may be earned by the Grantee is 0 to 300% of the Target Award. The Performance Shares that will vest, if at all, are the Adjusted Performance Shares determined based on the performance metrics set forth in Exhibit A to this Agreement; provided that, subject to the provisions of Section 4, the Grantee remains in continuous employment with the Company through the last day of the Performance Period (as defined below). For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.

2.PerformancePeriod.Subject to the provisions of Section 4, Performance Shares will be paid to the Grantee, if at all, following the close of the performance period beginning on December 31, 2019 and ending on December 31, 2022 (the "Performance Period") based upon the Company's achievement of the performance metrics set forth in Exhibit A.

3.Payment of Performance Shares. Upon vesting of the Adjusted Performance Shares in accordance with Exhibit A or Section 4, the Adjusted Performance Shares shall be settled in cash, in each case subject to Section 7. For those Adjusted Performance Shares settleable in cash, the Grantee shall be entitled to receive a cash lump sum payment in an amount that is equal to (i)

the average closing price of a share of Common Stock during the twenty (20) day trading period ending on last day of the Performance Period (the "Vesting Date") multiplied by (ii) the Adjusted Performance Shares. The payment shall be made or shares of Common Stock delivered within forty-five (45) calendar days from the Vesting Date.

4.Termination of Employment; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee's employment with the Company as a result of the death or Disability of the Grantee, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of such termination of employment was the last day of the Performance Period. For purposes hereof, "Disability" shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.

(b)Qualified Separation from Service. If the Grantee's employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if December 31 of the year of such termination of employment was the last day of the Performance Period. For purposes hereof, a "Qualified Separation from Service" is defined as a termination of Grantee's employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.

For purposes hereof, "Cause" is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee's employment with the Company of any of the restrictive covenants set out in the Grantee's employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee's duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee's illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee's part shall be deemed "willful" unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee's fiduciary duties to the Company, including, without limitation, the duties of

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care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.

(c)Termination following a Change in Control. In the event of the Grantee's termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of the Change in Control was the last day of the Performance Period.

(d)Company Equity Acceleration Benefits and Carrizo CIC Plan Inapplicable. Notwithstanding anything to the contrary contained herein, but subject to Section 4(c), the Carrizo Oil & Gas Inc. Change in Control Severance Plan (as may be amended from time to time) (the "Carrizo CIC Plan") and any other potential rights to equity acceleration benefits in connection with a termination of employment related to the merger of Carrizo Oil & Gas, Inc. with and into the Company (the "Other Acceleration Benefits") shall not apply to the Performance Shares granted hereunder. As a condition of receiving this Award, Grantee hereby expressly acknowledges and agrees that, notwithstanding anything set forth in the Carrizo CIC Plan to the contrary, the Change in Control Benefits (as defined in the Carrizo CIC Plan), the Severance Benefits (as set forth in Section 3.02(c)(3) of the Carrizo CIC Plan), and the Other Acceleration Benefits shall not apply to the Performance Shares granted hereunder, and hereby waives any right to any equity acceleration benefits provided for under the Carrizo CIC Plan or the Other Acceleration Benefits with respect to this award of Performance Shares. In the event this Section 4(d) should be held by a court of competent jurisdiction to be unenforceable, this Agreement shall be terminated and of no further force or effect and all Performance Shares (whether vested or unvested) shall be immediately forfeited to the Company without any consideration.

(e)Forfeiture. Upon termination of the Grantee's employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Performance Shares shall be immediately forfeited to the Company.

5.Clawback Policy. The Grantee hereby acknowledges and agrees that all rights with respect to the Performance Shares are subject to the Company's Clawback Policy, as may be in effect from time to time. The Grantee further acknowledges and agrees that the the Performance Shares and amounts received with respect to the Performance Shares are subject to recoupment pursuant to the terms of the Company Clawback Policy.

6.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Performance Shares, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock. Notwithstanding the foregoing, prior to the vesting of the underlying Performance Shares, Dividend Equivalents shall be accrued on the Target Award, without interest, for the benefit

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of the Grantee. Dividend Equivalents shall be subject to the same vesting conditions as the underlying Performance Shares and shall be payable in cash at the same time as the Adjusted Performance Shares are settled pursuant to Section 3.

7.Mandatory Withholding of Taxes. Grantee acknowledges and agrees that the Company shall deduct from the cash otherwise payable or deliverable an amount of cash that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. The Grantee may elect to have the Company withhold from cash that would otherwise payable an amount of cash equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the cash otherwise payable.

8.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee's address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee's e‑mail address specified in the Company's records or e-mail address provided by the Grantee to the Company's Stock Plan Administrator.

9.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee's employment at any time, with or without cause; subject, however, to the provisions of the Grantee's employment agreement, if applicable.

10.Governing Law.This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any

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objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

11.Construction. References in this Agreement to "this Agreement" and the words "herein," "hereof," "hereunder" and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

12.Code Section 409A. Performance Shares under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a "specified employee" within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a "separation from service" (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee's separation from service, (2) the date of the Grantee's death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.

13.Excise Taxes. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a "disqualified individual" (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a "parachute payment" (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee's "base amount" (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a

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nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee's base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.

14.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company's Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

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Exhibit A

Calculation of the

Adjusted Performance Shares

1. General. The number of Performance Shares that performance vest under the Agreement will be determined based on the Company's relative Total Shareholder Return ("TSR") ranking as compared to the Company's performance peer group during the performance period, with a modifier based on the Company's annualized absolute TSR performance, as further described below (the "Adjusted Performance Shares").

For purposes herein, TSR shall be calculated as follows:

(EP + CD - BP)/BP = % increase or decrease

Ending price (EP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2022. 

Beginning price (BP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2019.

Cash Dividends (CD) - equals the cash dividends paid on a share of Common Stock during the Performance Period.

The Committee, in its sole discretion, may adjust TSR calculations as necessary for stock splits or other stock dividends.

2. Relative TSR Ranking. As soon as administratively practicable following the Vesting Date, the TSR of the Company and each of listed peer companies below shall be calculated.  The resulting percentage for the Company and the peer companies will then be ranked.  Based on the relative ranking, the number of Performance Shares that vest under the Agreement will be determined in accordance with the following table (subject to Section 3 of this Exhibit A):

– 1 –

Rank	Percent Rank	Payout
1	100.0%	200%
2	90.9%	182%
3	81.8%	164%
4	72.7%	145%
5	63.6%	127%
6	54.6%	109%
7	45.5%	91%
8	36.4%	73%
9	27.3%	55%
10	18.2%	36%
11	9.1%	18%
12	0.0%	0%

Peer Companies

Callon Petroleum (CPE)

Cimarex Energy Co. (XEC)

Centennial Resource Development (CDEV)

Magnolia Oil & Gas Corporation (MGY)

Matador Resources (MTDR)

Oasis Petroleum (OAS)

Parsley Energy (PE)

PDC Energy (PDCE)

QEP Resources (QEP)

SM Energy (SM)

Whiting Petroleum Corporation (WLL)

WPX Energy, Inc. (WPX)

In the event that during the Performance Period one or more of the listed peer companies is involved in a merger/acquisition, and (i) such merger/acquisition was announced on or prior to June 30, 2021, then such named peer company(s) will be replaced with a suitable replacement, as determined in the Committee's sole discretion or (ii) such merger/acquisition was announced after June 30, 2021, then such peer company(s) will move to the top or the bottom of the ranking, based on whether said peer company's Total Shareholder Return is greater or less than that for the Company, in each case measured as of the date of the announcement of such merger/acquisition.  If, during the Performance Period, any peer company declares bankruptcy or initiates (or becomes subject to) a similar proceeding as a debtor due to insolvency, then, for the purposes of ranking the peer companies and the Company, such peer company shall be ranked last.

3. Absolute TSR Modifier. Notwithstanding the foregoing, the number of Adjusted Performance Shares that shall vest will be determined by multiplying the payout (as a percentage of the Award) determined by the Company's relative TSR performance pursuant to Section 2 of this Exhibit A by the applicable multiplier set forth in the table below, based on the Company's annualized absolute TSR for the Performance Period. For example, if the Company's TSR ranking is at the 50th percentile, resulting in a 100% Payout

– 2 –

(as % of Award Earned) pursuant to Section 2 of this Exhibit A, but the absolute annualized Company TSR was 10% or greater, but less than 15%, then the final payout (as % of Award Earned) would be 100% * 125% = 125%.

Absolute Annualized Company TSR	Payout Multiplier (% of Payout Determined Pursuant to Section 2 of Exhibit A)
Greater than 15%	150%
10% or greater, but equal to or less than 15%	125%
Greater than 5%, but less than 10%	100%
0% to 5%	75%
Less than 0%	50%

– 3 –

EX-10.25

Exhibit 10.24

2020 EMPLOYEE PERFORMANCE SHARE AWARD AGREEMENT

(OFFICER PAID IN SHARES)

CALLON PETROLEUM COMPANY

AMENDED AND RESTATED 2018 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT ("Agreement") is effective as of [•] (the "Grant Date"), by and between Callon Petroleum Company, a Delaware corporation (the "Company"), and ____________________ (the "Grantee").

The Company has adopted the Amended and Restated Callon Petroleum Company 2018 Omnibus Incentive Plan (the "Plan"), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the performance shares provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee's personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Performance Shares.Pursuant to the Plan and subject further to the terms and conditions herein, the Company and Grantee enter into this Agreement pursuant to which the Grantee has a target of ________ performance shares (the "Target Award") where each performance share represents the right to receive one share of Common Stock (the "Performance Shares"). The range of Performance Shares which may be earned by the Grantee is 0 to 300% of the Target Award. The Performance Shares that will vest, if at all, are the Adjusted Performance Shares determined based on the performance metrics set forth in Exhibit A to this Agreement; provided that, subject to the provisions of Section 4, the Grantee remains in continuous employment with the Company through the last day of the Performance Period (as defined below). For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.

2.Performance Period.Subject to the provisions of Section 4, Performance Shares will be paid to the Grantee, if at all, following the close of the performance period beginning on December 31, 2019 and ending on December 31, 2022 (the "Performance Period") based upon the Company's achievement of the performance metrics set forth in Exhibit A.

3.Payment of Performance Shares. Upon vesting of the Adjusted Performance Shares in accordance with Exhibit A or Section 4, the Adjusted Performance Shares shall be settled in Common Stock subject to Section 7. For each Adjusted Performance Share settleable in Common Stock, the Grantee shall be entitled to receive one share of Common Stock. The shares of Common

Stock shall be delivered within forty-five (45) calendar days from the last day of the Performance Period (the "Vesting Date").

4.Termination of Employment; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee's employment with the Company as a result of the death or Disability of the Grantee, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of such termination of employment was the last day of the Performance Period. For purposes hereof, "Disability" shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.

(b)Qualified Separation from Service. If the Grantee's employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if December 31 of the year of such termination of employment was the last day of the Performance Period. For purposes hereof, a "Qualified Separation from Service" is defined as a termination of Grantee's employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.

For purposes hereof, "Cause" is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee's employment with the Company of any of the restrictive covenants set out in the Grantee's employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee's duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee's illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee's part shall be deemed "willful" unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee's fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in

– 2 –

a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.

(c)Termination following a Change in Control. In the event of the Grantee's termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, occurring after the Grant Date, the Performance Shares shall immediately vest, with the number of Adjusted Performance Shares determined in accordance with Exhibit A, as if the date of the Change in Control was the last day of the Performance Period.

(d)Company Equity Acceleration Benefits and Carrizo CIC Plan Inapplicable. Notwithstanding anything to the contrary contained herein, but subject to Section 4(c), the Carrizo Oil & Gas Inc. Change in Control Severance Plan (as may be amended from time to time) (the "Carrizo CIC Plan") and any other potential rights to equity acceleration benefits in connection with a termination of employment related to the merger of Carrizo Oil & Gas, Inc. with and into the Company (the "Other Acceleration Benefits") shall not apply to the Performance Shares granted hereunder. As a condition of receiving this Award, Grantee hereby expressly acknowledges and agrees that, notwithstanding anything set forth in the Carrizo CIC Plan to the contrary, the Change in Control Benefits (as defined in the Carrizo CIC Plan), the Severance Benefits (as set forth in Section 3.02(c)(3) of the Carrizo CIC Plan) and the Other Acceleration Benefits shall not apply to the Performance Shares granted hereunder, and hereby waives any right to any equity acceleration benefits provided for under the Carrizo CIC Plan or the Other Acceleration Benefits with respect to this award of Performance Shares. In the event this Section 4(d) should be held by a court of competent jurisdiction to be unenforceable, this Agreement shall be terminated and of no further force or effect and all Performance Shares (whether vested or unvested) shall be immediately forfeited to the Company without any consideration.

(e)Forfeiture. Upon termination of the Grantee's employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Performance Shares shall be immediately forfeited to the Company.

5.Clawback Policy. The Grantee hereby acknowledges and agrees that all rights with respect to the Performance Shares are subject to the Company's Clawback Policy, as may be in effect from time to time. The Grantee further acknowledges and agrees that the the Performance Shares and amounts received with respect to the Performance Shares are subject to recoupment pursuant to the terms of the Company Clawback Policy.

6.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Performance Shares, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section 3. Notwithstanding the foregoing, prior to the vesting of the underlying Performance Shares, Dividend Equivalents shall be accrued on the Target Award, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting

– 3 –

conditions as the underlying Performance Shares and shall be payable in cash at the same time as the Adjusted Performance Shares are settled pursuant to Section 3.

7.Mandatory Withholding of Taxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee's tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then, the Grantee, subject to compliance with the Company's insider trading policies, authorizes the Company or the Company's Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock that would otherwise be deliverable a number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock otherwise deliverable.

8.Restrictions Imposed by Law.Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

9.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Law Department

– 4 –

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee's address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee's e‑mail address specified in the Company's records or e-mail address provided by the Grantee to the Company's Stock Plan Administrator.

10.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee's employment at any time, with or without cause; subject, however, to the provisions of the Grantee's employment agreement, if applicable.

11.Governing Law.This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

12.Construction. References in this Agreement to "this Agreement" and the words "herein," "hereof," "hereunder" and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

13.Code Section 409A. Performance Shares under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a "specified employee" within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a "separation from service" (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee's separation from service, (2) the date of the Grantee's death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.

– 5 –

14.Excise Taxes. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a "disqualified individual" (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a "parachute payment" (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee's "base amount" (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee's base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.

15.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company's Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

– 6 –

Exhibit A

Calculation of the

Adjusted Performance Shares

1. General. The number of Performance Shares that performance vest under the Agreement will be determined based on the Company's relative Total Shareholder Return ("TSR") ranking as compared to the Company's performance peer group during the performance period, with a modifier based on the Company's absolute annualized TSR performance, as further described below (the "Adjusted Performance Shares").

For purposes herein, TSR shall be calculated as follows:

(EP + CD - BP)/BP = % increase or decrease

Ending price (EP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2022. 

Beginning price (BP) - equals the average closing price of a share of Common Stock during the twenty (20) day trading period ending December 31, 2019.

Cash Dividends (CD) - equals the cash dividends paid on a share of Common Stock during the Performance Period.

The Committee, in its sole discretion, may adjust TSR calculations as necessary for stock splits or other stock dividends.

2. Relative TSR Ranking. As soon as administratively practicable following the Vesting Date, the TSR of the Company and each of listed peer companies below shall be calculated.  The resulting percentage for the Company and the peer companies will then be ranked.  Based on the relative ranking, the number of Performance Shares that vest under the Agreement will be determined in accordance with the following table (subject to Section 3 of this Exhibit A):

– 1 –

Rank	Percent Rank	Payout
1	100.0%	200%
2	90.9%	182%
3	81.8%	164%
4	72.7%	145%
5	63.6%	127%
6	54.6%	109%
7	45.5%	91%
8	36.4%	73%
9	27.3%	55%
10	18.2%	36%
11	9.1%	18%
12	0.0%	0%

Peer Companies

Callon Petroleum (CPE)

Cimarex Energy Co. (XEC)

Centennial Resource Development (CDEV)

Magnolia Oil & Gas Corporation (MGY)

Matador Resources (MTDR)

Oasis Petroleum (OAS)

Parsley Energy (PE)

PDC Energy (PDCE)

QEP Resources (QEP)

SM Energy (SM)

Whiting Petroleum Corporation (WLL)

WPX Energy, Inc. (WPX)

In the event that during the Performance Period one or more of the listed peer companies is involved in a merger/acquisition, and (i) such merger/acquisition was announced on or prior to June 30, 2021, then such named peer company(s) will be replaced with a suitable replacement, as determined in the Committee's sole discretion or (ii) such merger/acquisition was announced after June 30, 2021, then such peer company(s) will move to the top or the bottom of the ranking, based on whether said peer company's Total Shareholder Return is greater or less than that for the Company, in each case measured as of the date of the announcement of such merger/acquisition.  If, during the Performance Period, any peer company declares bankruptcy or initiates (or becomes subject to) a similar proceeding as a debtor due to insolvency, then, for the purposes of ranking the peer companies and the Company, such peer company shall be ranked last.

3. Absolute TSR Modifier. Notwithstanding the foregoing, the number of Adjusted Performance Shares that shall vest will be determined by multiplying the payout (as a percentage of the Award) determined by the Company's relative TSR performance pursuant to Section 2 of this Exhibit A by the applicable multiplier set forth in the table below, based on the Company's absolute annualized TSR for the Performance Period. For example, if the Company's TSR ranking is at the 50th percentile, resulting in a 100% Payout

– 2 –

(as % of Award Earned) pursuant to Section 2 of this Exhibit A, but the absolute annualized Company TSR was 10% or greater, but less than 15%, then the final payout (as % of Award Earned) would be 100% * 125% = 125%.

Absolute Annualized Company TSR	Payout Multiplier (% of Payout Determined Pursuant to Section 2 of Exhibit A)
Greater than 15%	150%
10% or greater, but equal to or less than 15%	125%
Greater than 5%, but less than 10%	100%
0% to 5%	75%
Less than 0%	50%

– 3 –

EX-10.26

Exhibit 10.25

2020 EMPLOYEE RESTRICTED STOCK UNIT AWARD AGREEMENT (OFFICER)

CALLON PETROLEUM COMPANY

AMENDED AND RESTATED 2018 OMNIBUS INCENTIVE PLAN

THIS AGREEMENT ("Agreement") is effective as of [•] (the "Grant Date"), by and between Callon Petroleum Company, a Delaware corporation (the "Company"), and ____________________ (the "Grantee").

The Company has adopted the Amended and Restated Callon Petroleum Company 2018 Omnibus Incentive Plan (the "Plan"), which by this reference is made a part hereof, for the benefit of eligible employees, directors and independent contractors of the Company and its Subsidiaries. Capitalized terms used and not otherwise defined herein shall have the meaning ascribed thereto in the Plan.

Pursuant to the Plan, the Committee, which has generally been assigned responsibility for administering the Plan, has determined that it would be in the interest of the Company and its stockholders to grant the restricted stock units provided herein in order to provide Grantee with additional remuneration for services rendered, to encourage Grantee to remain in the employ of the Company or its Subsidiaries and to increase Grantee's personal interest in the continued success and progress of the Company.

The Company and Grantee therefore agree as follows:

1.Grant of Restricted Stock Units. Subject to the terms and conditions herein, effective as of the Grant Date, the Company hereby awards to the Grantee, pursuant to the Plan, a right to receive __________ shares of Common Stock of the Company, par value $.01 per share (the "Restricted Stock Units").

2.Vesting Schedule and Settlement.

Subject to the provisions of Section ý3 hereof, the Restricted Stock Units shall vest in one-third increments (rounded up to the nearest whole number) on each of April 1, 2021, April 1, 2022 and April 1, 2023 (each, a "Vesting Date"); provided that the Grantee remains in continuous employment with the Company through the applicable Vesting Date. For purposes of this Agreement, references to employment with the Company include employment with any successor to the Company as well as employment with any Subsidiary.

As soon as practicable (but in no event later than thirty (30) days) following the occurrence of the Vesting Date or vesting pursuant to Section ý3, subject to Section 6, the Company shall deliver to the Grantee or, as applicable, the Grantee's legal representative, estate, beneficiary or heir certificates representing the applicable number shares of Common Stock or cause the applicable number of shares of Common Stock to be evidenced in book entry form in the Grantee's name in the stock register of the Company maintained by the Company's transfer agent.

3.Termination of Employment; Forfeiture.

(a)Death and Disability. Upon termination of the Grantee's employment with the Company as a result of the death or Disability of the Grantee, the Restricted Stock Units shall immediately vest. For purposes hereof, "Disability" shall mean the physical or mental inability of Grantee to carry out the normal and usual duties of his position on a full-time basis for an entire period of six (6) continuous months together with the reasonable likelihood, as determined by the Committee, that Grantee, upon the advice of a qualified physician, will be unable to carry out the normal and usual duties of his position.

(b)Qualified Separation from Service. If the Grantee's employment is terminated due to a Qualified Separation from Service, the Committee may determine, in its sole discretion, that all remaining unvested Restricted Stock Units shall be 100% vested as of such termination date.  For purposes hereof, a "Qualified Separation from Service" is defined as a termination of Grantee's employment with the Company, other than for Cause, provided that, as of the date of such termination (i) Grantee has attained a minimum of ten (10) years of employment with the Company, (ii) Grantee has attained the age of fifty-five (55), (iii) in the event such termination of employment is a voluntary termination by the Grantee, the Grantee has provided the Company with a notice of such intent to terminate at least six months prior to the termination date and (iv) Grantee enters into an agreement not to compete with the Company and its Affiliates for a period of at least one year, which agreement, both in form and substance, is provided by the Committee or is otherwise satisfactory to the Committee.

For purposes hereof, "Cause" is defined as: (i) the conviction of the Grantee by a court of competent jurisdiction as to which no further appeal can be taken of a crime involving moral turpitude or a felony or entering the plea of nolo contendere to such crime by the Grantee; (ii) the commission by the Grantee of a material act of fraud upon the Company, any Subsidiary or Affiliate; (iii) the material misappropriation by the Grantee of any funds or other property of the Company, any Subsidiary or Affiliate; (iv) the knowing engagement by the Grantee without the written approval of the Board, in any material activity which directly competes with the business of the Company, any Subsidiary or Affiliate, or which would directly result in material injury to the business or reputation of the Company or any Subsidiary or Affiliate; (v)(1) a material breach by the Grantee during the Grantee's employment with the Company of any of the restrictive covenants set out in the Grantee's employment agreement with the Company, if applicable, or (2) the willful and material nonperformance of the Grantee's duties to the Company or any Subsidiary or Affiliate (other than by reason of the Grantee's illness or incapacity), and, for purposes of this clause (v), no act or failure to act on Grantee's part shall be deemed "willful" unless it is done or omitted by the Grantee not in good faith and without his reasonable belief that such action or omission was in the best interest of the Company, (vi) any breach of the Grantee's fiduciary duties to the Company, including, without limitation, the duties of care, loyalty and obedience to the law; and (vii) the intentional failure of the Grantee to comply with the Company's Code of Business Conduct and Ethics, or to otherwise discharge his duties in good faith and in a manner that the Grantee reasonably believes to be in the best interests of the Company, and with the care an ordinarily prudent person in a like position would exercise under similar circumstances.

(c)Termination following a Change in Control. In the event of the Grantee's termination of employment by the Company for any reason other than Cause within the two-year period immediately following the effective date of a Change in Control, all remaining unvested Restricted Stock Units shall be 100% vested a of such termination date.

– 2 –

(d)Company Equity Acceleration Benefits and Carrizo CIC Plan Inapplicable. Notwithstanding anything to the contrary contained herein, but subject to Section 4(c), the Carrizo Oil & Gas Inc. Change in Control Severance Plan (as may be amended from time to time) (the "Carrizo CIC Plan") and any other potential rights to equity acceleration benefits in connection with a termination of employment related to the merger of Carrizo Oil & Gas, Inc. with and into the Company (the "Other Acceleration Benefits") shall not apply to the Restricted Stock Units granted hereunder. As a condition of receiving this Award, Grantee hereby expressly acknowledges and agrees that, notwithstanding anything set forth in the Carrizo CIC Plan to the contrary, the Change in Control Benefits (as defined in the Carrizo CIC Plan), the Severance Benefits (as set forth in Section 3.02(c)(3) of the Carrizo CIC Plan) and the Other Acceleration Benefits shall not apply to the Restricted Stock Units granted hereunder, and hereby waives any right to any equity acceleration benefits provided for under the Carrizo CIC Plan or the Other Acceleration Benefits with respect to this award of Restricted Stock Units. In the event this Section 4(d) should be held by a court of competent jurisdiction to be unenforceable, this Agreement shall be terminated and of no further force or effect and all Restricted Stock Units (whether vested or unvested) shall be immediately forfeited to the Company without any consideration.

(e)Forfeiture. Upon termination of the Grantee's employment with the Company for any reason other than death, Disability, Qualified Separation from Service with accelerated vesting by the Committee, or a termination without Cause following a Change in Control, all unvested Restricted Stock Units shall be immediately forfeited to the Company.

4.Clawback Policy. The Grantee hereby acknowledges and agrees that all rights with respect to the Restricted Stock Units are subject to the Company's Clawback Policy, as may be in effect from time to time. The Grantee further acknowledges and agrees that the Restricted Stock Units and amounts received with respect to the Restricted Stock Units are subject to recoupment pursuant to the terms of the Company Clawback Policy.

5.No Ownership Rights Prior to Issuance of Shares of Common Stock; Dividend Equivalents. Neither the Grantee nor any other person shall become the beneficial owner of the shares of Common Stock underlying the Restricted Stock Units, nor have any rights of a shareholder (including, without limitation, dividend and voting rights) with respect to any such shares of Common Stock, unless and until and after such shares of Common Stock have been delivered to the Grantee as described in Section ý2. Notwithstanding the foregoing, prior to the vesting of the underlying Restricted Stock Units, Dividend Equivalents shall be accrued, without interest, for the benefit of the Grantee. Dividend Equivalents shall be subject to the same vesting schedule as the underlying Restricted Stock Units and shall be payable in cash at the same time as the Restricted Stock Units are settled pursuant to Section 2.

6.Mandatory Withholding ofTaxes. Grantee acknowledges and agrees that the Company shall deduct from the shares of Common Stock otherwise deliverable a number of shares of Common Stock (valued at their Fair Market Value) on the applicable date that is equal to the amount of all federal, state and local taxes required to be withheld by the Company. In the event the Company, in its sole discretion, determines that the Grantee's tax obligations will not be satisfied under the method otherwise expressly described above and the Grantee does not provide payment to the Company in the form of shares of Common Stock (valued at their Fair Market Value) sufficient to satisfy any withholding obligations, then the Grantee, subject to compliance with the Company's insider trading policies, authorizes the Company or the

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Company's Stock Plan Administrator, currently Fidelity, to (i) sell a number of shares of Common Stock issued or outstanding pursuant to the Award, which number of shares of Common Stock the Company determines has at least the market value sufficient to meet the tax withholding obligations, plus additional shares of Common Stock to account for rounding and market fluctuations and (ii) pay such tax withholding to the Company. The Grantee may elect to have the Company withhold or purchase, as applicable, from shares of Common Stock or cash that would otherwise payable or deliverable an amount of cash and/or number of shares of Common Stock (valued at their Fair Market Value) equal to the product of the maximum federal marginal rate that could be applicable to the Grantee and the Fair Market Value of the shares of Common Stock or cash otherwise payable or deliverable, as applicable.

7.Restrictions Imposed by Law. Without limiting the generality of Section 16 of the Plan, the Grantee agrees that the Company will not be obligated to deliver any shares of Common Stock if counsel to the Company determines that such delivery would violate any applicable law or any rule or regulation of any governmental authority or any rule or regulation of, or agreement of the Company with, any securities exchange or association upon which the Common Stock is listed or quoted. The Company shall in no event be obligated to take any affirmative action in order to cause the issuance or delivery of shares of Common Stock to comply with any such law, rule, regulation or agreement.

8.Notice. Unless the Company notifies the Grantee in writing of a different procedure, any notice or other communication to the Company with respect to this Agreement shall be in writing and shall be delivered personally or sent by first class mail, postage prepaid to the following address:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Human Resources

with a copy to:

Callon Petroleum Company

2000 W. Sam Houston Parkway South, Suite 2000

Houston, Texas 77042

Attention: Law Department

Any notice or other communication to the Grantee with respect to this Agreement shall be in writing and shall be delivered personally, and (i) shall be sent by first class mail, postage prepaid, to Grantee's address as listed in the records of the Company on the Grant Date, unless the Company has received written notification from the Grantee of a change of address, or (ii) shall be sent to the Grantee's e‑mail address specified in the Company's records or e-mail address provided by the Grantee to the Company's Stock Plan Administrator.

9.Grantee Employment. Nothing contained in this Agreement, and no action of the Company or the Committee with respect hereto, shall confer or be construed to confer on the Grantee any right to continue in the employ of the Company or interfere in any way with the right of the Company to terminate the Grantee's employment at any time, with or without cause; subject, however, to the provisions of the Grantee's employment agreement, if applicable.

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10.Governing Law. This Agreement shall be governed by, and construed in accordance with, the internal laws of the State of Delaware. Any suit, action or other legal proceeding arising out of this Agreement shall be brought in the United States District Court for the Southern District of Texas, Houston Division, or, if such court does not have jurisdiction or will not accept jurisdiction, in any court of general jurisdiction in Harris County, Texas. Each of the Grantee and the Company consents to the jurisdiction of any such court in any such suit, action, or proceeding and waives any objection that it may have to the laying of venue of any such suit, action, or proceeding in any such court.

11.Construction. References in this Agreement to "this Agreement" and the words "herein," "hereof," "hereunder" and similar terms include all exhibits and schedules appended hereto, including the Plan. This Agreement is entered into, and the Award evidenced hereby is granted, pursuant to the Plan and shall be governed by and construed in accordance with the Plan and the administrative interpretations adopted by the Committee thereunder. All decisions of the Committee upon questions regarding the Plan or this Agreement shall be conclusive. Unless otherwise expressly stated herein, in the event of any inconsistency between the terms of the Plan and this Agreement, the terms of the Plan shall control. The headings of the sections of this Agreement have been included for convenience of reference only, are not to be considered a part hereof and shall in no way modify or restrict any of the terms or provisions hereof.

12.Code Section 409A. Restricted Stock Units under this Agreement are designed to be exempt from or comply with Section 409A of the Code and the related Treasury Regulations thereunder and the provisions of this Agreement will be administered, interpreted and construed accordingly (or disregarded to the extent such provision cannot be so administered, interpreted, or construed). If the Grantee is identified by the Company as a "specified employee" within the meaning of Code Section 409A(a)(2)(B)(i) on the date on which the Grantee has a "separation from service" (other than due to death) within the meaning of Treasury Regulation § 1.409A-1(h), any amount payable or settled under this Agreement on account of a separation from service that is deferred compensation subject to Section 409A of the Code shall be paid or settled on the earliest of (1) the first business day following the expiration of six months from the Grantee's separation from service, (2) the date of the Grantee's death, or (3) such earlier date as complies with the requirements of Section 409A of the Code.

13.Excise Taxes. Notwithstanding anything to the contrary in this Agreement, if the Grantee is a "disqualified individual" (as defined in Code Section 280G(c)), and the payments and benefits provided for under this Agreement, together with any other payments and benefits which the Grantee has the right to receive from the Company or any of its affiliates or any party to a transaction with the Company or any of its affiliates, would constitute a "parachute payment" (as defined in Code Section 280G(b)(2)), then the payments and benefits provided for under this Agreement shall be either (a) reduced (but not below zero) so that the present value of such total amounts and benefits received by the Grantee from the Company and its affiliates will be one dollar ($1.00) less than three times the Grantee's "base amount" (as defined in Code Section 280G(b)(3)) and so that no portion of such amounts and benefits received by the Grantee shall be subject to the excise tax imposed by Code Section 4999 or (b) paid in full, whichever produces the better net after-tax position to the Grantee (taking into account any applicable excise tax under Code Section 4999 and any other applicable taxes). The reduction of payments and benefits hereunder, if applicable, shall be made by reducing payments or benefits to be paid hereunder in the order in which such payment or benefit would be paid or provided (beginning with such payment or benefit that would be made last in time and continuing, to the extent necessary, through to such payment or benefit that would be made

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first in time). The determination as to whether any such reduction in the amount of the payments and benefits provided hereunder is necessary shall be made by a nationally recognized accounting firm selected by the Company. If a reduced payment or benefit is made or provided and through error or otherwise that payment or benefit, when aggregated with other payments and benefits from the Company (or its affiliates) used in determining if a parachute payment exists, exceeds one dollar ($1.00) less than three times the Grantee's base amount, then the Grantee shall immediately repay such excess to the Company upon notification that an overpayment has been made.

14.Grantee Acceptance. The Grantee shall accept the terms and conditions of this Agreement through the online acceptance procedures set forth by the Company's Stock Plan Administrator. By electronically accepting this Agreement the Grantee acknowledges receipt of a copy of the Plan and hereby accepts this Award subject to all the terms and provisions hereof and thereof.

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EX-21.1

Exhibit 21.1

Subsidiaries of Callon Petroleum Company
Name	State of Incorporation
Callon Petroleum Operating Company	Delaware
Callon (Permian) LLC	Delaware
Callon (Eagle Ford) LLC	Delaware

EX-23.1

Exhibit 23.1

CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

We have issued our reports dated February 28, 2020, with respect to the consolidated financial statements and internal control over financial reporting included in the Annual Report of Callon Petroleum Company on Form 10-K for the year ended December 31, 2019. We consent to the incorporation by reference of said reports in the Registration Statements of Callon Petroleum Company on Forms S-3ASR (File No. 333-230748 and File No. 333-235634) and on Forms S-8 (File No. 333-109744, File No. 333-176061, File No. 333-188008, File No. 333-212044, File No. 333-224829, File No. 333-235635, and File No. 333-235636).

/s/ GRANT THORNTON LLP

Houston, Texas

February 28, 2020

EX-23.2

Exhibit 23.2

[Letterhead]

February 28, 2020

Callon Petroleum Company

1401 Enclave Parkway, Suite 600

Houston, Texas

Ladies and Gentlemen:

We hereby consent to the use of the name DeGolyer and MacNaughton, to the references to us and to our reserves reports for the years ended December 31, 2017, December 31, 2018, and December 31, 2019, in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2019, references to DeGolyer and MacNaughton as an independent petroleum engineering consulting firm, to references to our report of third party dated February 12, 2020, containing our opinion on the proved reserves, as of December 31, 2019, attributable to certain properties in which Callon Petroleum Company has represented it holds an interest (our Report), and to the inclusion of our Report as an exhibit in Callon Petroleum Company’s Annual Report on Form 10-K for the year ended December 31, 2019. We also consent to all such references and to the incorporation by reference of our Report in the Registration Statements to be filed by Callon Petroleum Company on its Forms S-3ASR (File No. 333-230748 and File No. 333-235634) and on Forms S-8 (File No. 333-109744, File No. 333-176061, File No. 333-188008, File No. 333-212044, File No. 333-224829, File No. 333-235635, and File No. 333-235636).

Very truly yours,

/s/ DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON

Texas Registered Engineering Firm F-716

EX-23.3

Exhibit 23.3

CONSENT OF INDEPENDENT PETROLEUM ENGINEER

We hereby consent to the incorporation by reference in the registration statements on Forms S-3ASR (File No. 333-230748 and File No. 333-235634) and on Forms S-8 (File No. 333-109744, File No. 333-176061, File No. 333-188008, File No. 333-212044, File No. 333-224829, File No. 333-235635, and File No. 333-235636) of Callon Petroleum Company of our letter dated February 7, 2020, relating to estimates of proved reserves attributable to certain interests of Callon Petroleum Company as of December 31, 2019.

/s/ RYDER SCOTT COMPANY, L.P.

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

Houston, Texas

February 28, 2020

EX-31.1

Exhibit31.1

CERTIFICATIONS

I, Joseph C. Gatto, Jr., certify that:

1. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 28, 2020	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		President and Chief Executive Officer
		(Principal executive officer)

EX-31.2

Exhibit31.2

CERTIFICATIONS

I, James P. Ulm, II, certify that:

1. I have reviewed this Annual Report on Form 10-K of Callon Petroleum Company;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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;

c. Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures as of the end of the period covered by this report based on such evaluation; and

d. Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant's fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date:	February 28, 2020	/s/ James P. Ulm, II
		James P. Ulm, II
		Senior Vice President & Chief Financial Officer
		(Principal financial officer)

EX-32.1

Exhibit32.1

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350

In connection with the Annual Report on Form 10-K of Callon Petroleum Company for the year ended December 31, 2019, as filed with the Securities and Exchange Commission on the date hereof (the “Report”), the undersigned, in the capacities and on the dates indicated below, each hereby certify pursuant to 18 U.S.C. section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that the Report fully complies with requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934 and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

Date:	February 28, 2020	/s/ Joseph C. Gatto, Jr.
		Joseph C. Gatto, Jr.
		(Principal executive officer)
Date:	February 28, 2020	/s/ James P. Ulm, II
		James P. Ulm, II
		(Principal financial officer)

The foregoing certification is being furnished as an exhibit to the Report pursuant to Item 601(b)(32) of Regulation S-K and Section 906 of the Sarbanes-Oxley Act of 2002 (subsections (a) and (b) of Section 1350, Chapter 63 of Title 18, United States Code) and, accordingly, is not being filed as part of the Report for purposes of Section 18 of the Securities Exchange Act of 1934, as amended, and is not incorporated by reference into any filing of the Company, whether made before or after the date hereof, regardless of any general incorporation language in such filing.

EX-99.1

DeGolyer and MacNaughton

5001 Spring Valley Road

Suite 800 East

Dallas, Texas 75244

Exhibit 99.1

February 12, 2020

Callon Petroleum Company

2000 W. Sam Houston Parkway South

Suite 2000

Houston, Texas 77042

Ladies and Gentlemen:

Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2019, of the extent and value of the estimated net proved oil, condensate, and gas reserves of certain properties in which Callon Petroleum Company (Callon) has represented it holds an interest. This evaluation was completed on February 12, 2020. The properties evaluated herein are located in Texas. Callon has represented that these properties account for a portion of Callon’s net proved reserves as of December 31, 2019. Based on information provided by Callon, the third party estimate conducted by DeGolyer and MacNaughton addresses 45 percent of the total proved developed net oil and condensate reserves, 49 percent of the total proved developed net gas reserves, 35 percent of the total proved undeveloped net oil and condensate reserves, and 34 percent of the total proved undeveloped net gas reserves of Callon. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the Securities and Exchange Commission (SEC) of the United States. This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by Callon.

Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2019. Net reserves are defined as that portion of the gross reserves attributable to the interests held by Callon after deducting all interests held by others.

Values for proved reserves in this report are expressed in terms of future gross revenue, future net revenue, and present worth. Future gross revenue is defined as that revenue which will accrue to the evaluated interests from the production and sale of the estimated net reserves. Future net revenue is calculated by deducting production taxes, ad valorem taxes, operating expenses, capital costs, and abandonment costs from future gross revenue. Operating expenses include field operating expenses, transportation and processing expenses, compression charges, and an allocation of overhead that directly relates to production activities. Capital costs include drilling and completion costs, facilities costs, and field maintenance costs. Abandonment costs are represented by Callon to be inclusive of those costs associated with the removal of equipment,

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plugging of wells, and reclamation and restoration associated with the abandonment. At the request of Callon, future income taxes were not taken into account in the preparation of these estimates. Present worth is defined as future net revenue discounted at the nominal discount rate of 10 percent per year compounded monthly over the expected period of realization. Present worth should not be construed as fair market value because no consideration was given to additional factors that influence the prices at which properties are bought and sold.

Estimates of reserves and revenue should be regarded only as estimates that may change as production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information.

Information used in the preparation of this report was obtained from Callon and from public sources. In the preparation of this report we have relied, without independent verification, upon information furnished by Callon with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination of the properties was not considered necessary for the purposes of this report.

Definition of Reserves

Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used by us in this report are in accordance with the reserves definitions of Rules 4–10(a)

(1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows:

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Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12‑month period prior to the ending date of the period covered by

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the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty.

Methodology and Procedures

Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the

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Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019” and in Monograph 3 and Monograph 4 published by the Society of Petroleum Evaluation Engineers. The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history.

Based on the current stage of field development, production performance, the development plans provided by Callon, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The proved undeveloped reserves estimates were based on opportunities identified in the plan of development provided by Callon.

Callon has represented that its senior management is committed to the development plan provided by Callon and that Callon has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities.

For the evaluation of unconventional reservoirs, a performance-based methodology integrating the appropriate geology and petroleum engineering data was utilized for this report. Performance-based methodology primarily includes (1) production diagnostics, (2) decline-curve analysis, and (3) model-based analysis (if necessary, based on availability of data). Production diagnostics include data quality control, identification of flow regimes, and characteristic well performance behavior. These analyses were performed for all well groupings (or type-curve areas).

Characteristic rate-decline profiles from diagnostic interpretation were translated to modified hyperbolic rate profiles, including one or multiple b-exponent values followed by an exponential decline. Based on the availability of data, model-based analysis may be integrated to evaluate long-term decline behavior, the effect of dynamic reservoir and fracture parameters on well performance, and complex situations sourced by the nature of unconventional reservoirs.

In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available.

Data provided by Callon from wells drilled through December 31, 2019, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through November 2019. Estimated cumulative production, as of December 31, 2019, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month.

Oil and condensate reserves estimated herein are to be recovered by normal field separation and are expressed in thousands of barrels (Mbbl). In these estimates, 1 barrel equals 42 United States gallons. For

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reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity.

Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas reserves are expressed at a temperature base of 60 degrees Fahrenheit (°F) and at a pressure base of 14.65 pounds per square inch absolute (psia). Gas reserves included in this report are expressed in millions of cubic feet (MMcf).

Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in oil at initial reservoir conditions. Gas quantities estimated herein include both associated and nonassociated gas.

At the request of Callon, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. This conversion factor was provided by Callon.

Primary Economic Assumptions

Revenue values in this report were estimated using initial prices, expenses, and costs provided by Callon. Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the revenue values reported herein:

Oil and Condensate Prices

Callon has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Callon supplied differentials to a West Texas Intermediate reference price of $55.69 per barrel and the prices were held constant thereafter. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $53.04 per barrel of oil and condensate.

Gas Prices

7

DeGolyer and MacNaughton

Callon has represented that the gas prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12‑month period prior to the end of the reporting period, unless prices are defined by contractual agreements. Callon supplied differentials to the Henry Hub gas reference price of $2.58 per million Btu and the prices were held constant thereafter. These price differentials include revenue from the sale of natural gas liquids attributable to Callon. Btu factors provided by Callon were used to convert prices from dollars per million Btu to dollars per thousand cubic feet. The volume-weighted average price attributable to the estimated proved reserves over the lives of the properties was $2.079 per thousand cubic feet of gas.

Production and Ad Valorem Taxes

Production taxes were calculated using the tax rates for Texas. Ad valorem taxes were calculated using rates provided by Callon based on recent payments.

Operating Expenses, Capital Costs, and Abandonment Costs

Estimates of operating expenses, provided by Callon and based on current expenses, were held constant for the lives of the properties. Future capital expenditures were estimated using 2019 values, provided by Callon, and were not adjusted for inflation. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by Callon for all properties and were not adjusted for inflation. Operating expenses, capital costs, and abandonment costs were considered, as appropriate, in determining the economic viability of undeveloped reserves estimated herein.

Certain operating expenses and abandonment costs for the developed and undeveloped properties were provided by Callon at the field level and are shown as individual forecasts for each field in the appendix to this report. These field-level operating expenses and abandonment costs have not been allocated to the various individual properties within each field. The field-level operating expenses have, however, been included in determining the economic end of field life. Property projections were terminated at each property’s corresponding economic limit or economic end of field life, whichever occurs first.

8

DeGolyer and MacNaughton

In our opinion, the information relating to estimated proved reserves, estimated future net revenue from proved reserves, and present worth of estimated future net revenue from proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, 932-235-50-9, 932-235-50-30, and 932-235-50-31(a), (b), and (e) of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a) (1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that (i) future income tax expenses have not been taken into account in estimating the future net revenue and present worth values set forth herein and (ii) estimates of the proved developed and proved undeveloped reserves are not presented at the beginning of the year.

To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor.

Summary of Conclusions

The estimated net proved reserves, as of December 31, 2019, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (Mbbl), millions of cubic feet (MMcf), and thousands of barrels of oil equivalent (Mboe):

	Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2019
	Oil and Condensate (Mbbl)	Sales Gas (MMcf)	Oil Equivalent (Mboe)
Proved Developed	80,457	156,330	106,512
Proved Undeveloped	83,054	146,630	107,492
Total Proved	163,511	302,960	214,004
Note: Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent.

9

DeGolyer and MacNaughton

The estimated future revenue to be derived from the production and sale of the net proved reserves, as of December 31, 2019, of the properties evaluated using the guidelines established by the SEC is summarized as follows, expressed in thousands of dollars (M$):

	Proved Developed (M$)	Total Proved (M$)
Future Gross Revenue	4,590,589	9,302,198
Production and Ad Valorem Taxes	303,724	610,685
Operating Expenses	1,406,469	1,945,921
Capital and Abandonment Costs	61,434	1,227,659
Future Net Revenue	2,818,962	5,517,933
Present Worth at 10 Percent	1,583,424	2,424,743
Note: Future income taxes have not been taken into account in the preparation of these estimates.

While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2019, estimated reserves.

10

DeGolyer and MacNaughton

DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in Callon. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of Callon. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report.

Submitted,

/s/DeGolyer and MacNaughton

DeGOLYER and MacNAUGHTON                         Texas Registered Engineering Firm F-716

SIGNED: February 12, 2020

[SEAL]    

/s/Gregory K. Graves

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

DeGolyer and MacNaughton

CERTIFICATE of QUALIFICATION

I, Gregory K. Graves, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify:

1. That I am a Senior Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to Callon Petroleum Company dated February 12, 2020, and that I, as Senior Vice President, was responsible for the preparation of this report of third party.

2. That I attended the University of Texas at Austin, and that I graduated with a Bachelor of Science degree in Petroleum Engineering in the year 1984; that I am a Registered Professional Engineer in the State of Texas; that I am a member of the Society of Petroleum Engineers and the Society of Petroleum Evaluation Engineers; and that I have in excess of 35 years of experience in oil and gas reservoir studies and reserves evaluations.

[SEAL]    

/s/Gregory K. Graves

Gregory K. Graves, P.E.

Senior Vice President

DeGolyer and MacNaughton

EX-99.2

Exhibit 99.2

CALLON PETROLEUM COMPANY

Estimated

Future Reserves and Income

Attributable to Certain

Leasehold Interests

SEC Parameters

As of

December 31, 2019

\s\ Val Rick Robinson	\s\ Michael F. Stell
Val Rick Robinson, P.E.	Michael F. Stell, P.E.
TBPE License No. 105137	TBPE License No. 56416
Managing Senior Vice President	Associate Petroleum Engineer

[SEAL]                              [SEAL]

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

[Ryder Scott Company L.P. logo]

TBPE REGISTERED ENGINEERING FIRM F-1580        FAX (713) 651-0849

1100 LOUISIANA SUITE 4600    HOUSTON, TEXAS 77002-5294    TELEPHONE (713) 651-9191

February 7, 2020

Dr. Jeff Balmer, PHD. 

Callon Petroleum Company

2000 W. Sam Houston Parkway South,

Suite 2000

Houston, Texas 77042

Dear Dr. Balmer,

At your request, Ryder Scott Company, L.P. (Ryder Scott) has prepared an estimate of the proved reserves, future production, and income attributable to certain leasehold interests of Callon Petroleum Company (Callon) as of December 31, 2019. The subject properties are located in the state of Texas. The reserves and income data were estimated based on the definitions and disclosure guidelines of the United States Securities and Exchange Commission (SEC) contained in Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register (SEC regulations). Our third party study, completed on February 3, 2020 and presented herein, was prepared for public disclosure by Callon in filings made with the SEC in accordance with the disclosure requirements set forth in the SEC regulations.

The properties evaluated by Ryder Scott account for a portion of Callon’s total net proved reserves as of December 31, 2019. Based on information provided by Callon, the third party estimate conducted by Ryder Scott addresses 55 percent of the total proved developed net liquid hydrocarbon reserves, 51 percent of the total proved developed net gas reserves, 65 percent of the total proved undeveloped net liquid hydrocarbon reserves, and 61 percent of the total proved undeveloped net gas reserves of Callon.

The estimated reserves and future net income amounts presented in this report, as of December 31, 2019 are related to hydrocarbon prices. The hydrocarbon prices used in the preparation of this report are based on the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements, as required by the SEC regulations. Actual future prices may vary considerably from the prices required by SEC regulations. The recoverable reserves volumes and the income attributable thereto have a direct relationship to the hydrocarbon prices actually received; therefore, volumes of reserves actually recovered and the amounts of income actually received may differ significantly from the estimated quantities presented in this report. The results of this study are summarized as follows.

SUITE 800, 350 7TH AVENUE, S.W.    CALGARY, ALBERTA T2P 3N9    TEL (403) 262-2799    FAX (403) 262-2790

633 17TH STREET, SUITE 1700    DENVER, COLORADO 80202    TEL (303) 339-8110

Callon Petroleum Company

February 7, 2020

Page 2

SEC PARAMETERS

Estimated Net Reserves and Income Data

Certain Leasehold Interests of

Callon Petroleum Company

As of December 31, 2019

	Proved
	Developed						Total
	Producing		Non-Producing		Undeveloped		Proved
Net Reserves
Oil/Condensate –Barrels	72,198,382		31,408		110,620,231		182,850,021
Plant Products – Barrels	24,830,694		13,173		42,618,287		67,462,154
Gas – MMcf	164,270		76		289,827		454,173
Income Data ($M)
Future Gross Revenue		$4,373,375		$2,095		$6,635,091		$11,010,561
Deductions	1,705,754		1,578		3,705,643		5,412,975
Future Net Income (FNI)		$2,667,621	$	517		$2,929,448	$	5,597,586
Discounted FNI @ 10%		$1,663,026	$	352		$1,281,460	$	2,944,838

Liquid hydrocarbons are expressed in standard 42 U.S. gallon barrels. All gas volumes are reported on an “as sold basis” expressed in millions of cubic feet (MMcf) at the official temperature and pressure bases of the areas in which the gas reserves are located. In this report, the revenues, deductions, and income data are expressed as thousands of U.S. dollars ($M).

The estimates of the reserves, future production, and income attributable to properties in this report were prepared using the economic software packageARIES^TM Petroleum Economics and Reserves Software, a copyrighted program of Halliburton. The program was used at the request of Callon. Ryder Scott has found this program to be generally acceptable, but notes that certain summaries and calculations may vary due to rounding and may not exactly match the sum of the properties being summarized. Furthermore, one line economic summaries may vary slightly from the more detailed cash flow projections of the same properties, also due to rounding. The rounding differences are not material.

The future gross revenue is after the deduction of production taxes. The deductions incorporate the normal direct costs of operating the wells, ad valorem taxes, recompletion costs, development costs, and certain abandonment costs net of salvage. The “Other” deductions, as shown in the cash flow projections, include variable operating costs on a dollar per barrel and dollar per Mcf basis plus compression fees. The future net income is before the deduction of state and federal income taxes and general administrative overhead, and has not been adjusted for outstanding loans that may exist, nor does it include any adjustment for cash on hand or undistributed income.

Liquid hydrocarbon reserves account for approximately 95 percent and gas reserves account for the remaining 5 percent of total future gross revenue from proved reserves.

The discounted future net income shown above was calculated using a discount rate of 10 percent per annum compounded monthly. Future net income was discounted at four other discount rates which were also compounded monthly. These results are shown in summary form as follows.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Callon Petroleum Company

February 7, 2020

Page 3

	Discounted Future Net Income ($M)
	As of December 31, 2019
Discount Rate		Total
Percent		Proved
5		$3,899,308
15		$2,343,596
20		$1,933,906
25		$1,638,638

The results shown above are presented for your information and should not be construed as our estimate of fair market value.

Reserves Included in This Report

The proved reserves included herein conform to the definition as set forth in the Securities and Exchange Commission’s Regulations Part 210.4-10(a). An abridged version of the SEC reserves definitions from 210.4-10(a) entitled “PETROLEUM RESERVES DEFINITIONS” is included as an attachment to this report.

The various reserves status categories are defined in the attachment entitled “PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES” in this report. The proved developed non-producing reserves included herein consist of the shut-in status category.

No attempt was made to quantify or otherwise account for any accumulated gas production imbalances that may exist. The provedgas volumes presented herein do not include volumes of gas consumed in operations as reserves.

Reserves are “estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.” All reserves estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-categorized as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. At Callon’s request, this report addresses only the proved reserves attributable to the properties evaluated herein.

Proved oil and gas reserves are “those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible from a given date forward.” The proved reserves included herein were estimated using deterministic methods. The SEC has defined reasonable certainty for proved reserves, when based on deterministic methods, as a “high degree of confidence that the quantities will be recovered.”

Proved reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change. For proved reserves, the SEC states that “as changes due to increased availability of geoscience (geological, geophysical, and geochemical), engineering, and

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Callon Petroleum Company

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economic data are made to the estimated ultimate recovery (EUR) with time, reasonably certain EUR is much more likely to increase or remain constant than to decrease.” Moreover, estimates of proved reserves may be revised as a result of future operations, effects of regulation by governmental agencies or geopolitical or economic risks. Therefore, the proved reserves included in this report are estimates only and should not be construed as being exact quantities, and if recovered, the revenues therefrom, and the actual costs related thereto, could be more or less than the estimated amounts.

Callon’s operations may be subject to various levels of governmental controls and regulations. These controls and regulations may include, but may not be limited to, matters relating to land tenure and leasing, the legal rights to produce hydrocarbons, drilling and production practices, environmental protection, marketing and pricing policies, royalties, various taxes and levies including income tax and are subject to change from time to time. Such changes in governmental regulations and policies may cause volumes of proved reserves actually recovered and amounts of proved income actually received to differ significantly from the estimated quantities.

The estimates of proved reserves presented herein were based upon a detailed study of the properties in which Callon owns an interest; however, we have not made any field examination of the properties. No consideration was given in this report to potential environmental liabilities that may exist nor were any costs included for potential liabilities to restore and clean up damages, if any, caused by past operating practices.

Estimates of Reserves

The estimation of reserves involves two distinct determinations. The first determination results in the estimation of the quantities of recoverable oil and gas and the second determination results in the estimation of the uncertainty associated with those estimated quantities in accordance with the definitions set forth by the Securities and Exchange Commission’s Regulations Part 210.4-10(a). The process of estimating the quantities of recoverable oil and gas reserves relies on the use of certain generally accepted analytical procedures. These analytical procedures fall into three broad categories or methods: (1) performance-based methods, (2) volumetric-based methods and (3) analogy. These methods may be used individually or in combination by the reserves evaluator in the process of estimating the quantities of reserves. Reserves evaluators must select the method or combination of methods which in their professional judgment is most appropriate given the nature and amount of reliable geoscience and engineering data available at the time of the estimate, the established or anticipated performance characteristics of the reservoir being evaluated, and the stage of development or producing maturity of the property.

In many cases, the analysis of the available geoscience and engineering data and the subsequent interpretation of this data may indicate a range of possible outcomes in an estimate, irrespective of the method selected by the evaluator. When a range in the quantity of reserves is identified, the evaluator must determine the uncertainty associated with the incremental quantities of the reserves. If the reserves quantities are estimated using the deterministic incremental approach, the uncertainty for each discrete incremental quantity of the reserves is addressed by the reserves category assigned by the evaluator. Therefore, it is the categorization of reserves quantities as proved, probable and/or possible that addresses the inherent uncertainty in the estimated quantities reported. For proved reserves, uncertainty is defined by the SEC as reasonable certainty wherein the “quantities actually recovered are much more likely to be achieved than not.” The SEC states that “probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.” The SEC states that “possible reserves are those additional reserves that are less certain to be recovered than probable reserves and the total quantities ultimately recovered from a project

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Callon Petroleum Company

February 7, 2020

Page 5

have a low probability of exceeding proved plus probable plus possible reserves.” All quantities of reserves within the same reserves category must meet the SEC definitions as noted above.

Estimates of reserves quantities and their associated reserves categories may be revised in the future as additional geoscience or engineering data become available. Furthermore, estimates of reserves quantities and their associated reserves categories may also be revised due to other factors such as changes in economic conditions, results of future operations, effects of regulation by governmental agencies or geopolitical or economic risks as previously noted herein.

The proved reserves for the properties included herein were estimated by performance methods, analogy, or a combination of methods. All of the proved producing reserves attributable to producing wells and/or reservoirs were estimated by performance methods. The performance methods, such as decline curve analysis, utilized extrapolations of historical production and pressure data available through December 2019 in those cases where such data were considered to be definitive. The data utilized in this analysis were furnished to Ryder Scott by Callon or obtained from public data sources and were considered sufficient for the purpose thereof.

All of the proved undeveloped reserves included herein were estimated by analogy. The analogs utilized data furnished to Ryder Scott by Callon or which we have obtained from public data sources that were available through December 2019.

To estimate economically recoverable proved oil and gas reserves and related future net cash flows, we consider many factors and assumptions including, but not limited to, the use of reservoir parameters derived from geological, geophysical and engineering data which cannot be measured directly, economic criteria based on current costs and SEC pricing requirements, and forecasts of future production rates. Under the SEC regulations 210.4-10(a)(22)(v) and (26), proved reserves must be anticipated to be economically producible from a given date forward based on existing economic conditions including the prices and costs at which economic producibility from a reservoir is to be determined. While it may reasonably be anticipated that the future prices received for the sale of production and the operating costs and other costs relating to such production may increase or decrease from those under existing economic conditions, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Callon has informed us that they have furnished us all of the material accounts, records, geological and engineering data, and reports and other data required for this investigation. In preparing our forecast of future proved production and income, we have relied upon data furnished by Callon with respect to property interests owned, production and well tests from examined wells, normal direct costs of operating the wells or leases, other costs such as transportation and/or processing fees, ad valorem and production taxes, recompletion and development costs, development plans, abandonment costs after salvage, product prices based on the SEC regulations, adjustments or differentials to product prices, geological structural and isochore maps, well logs, core analyses, and pressure measurements. Ryder Scott reviewed such factual data for its reasonableness; however, we have not conducted an independent verification of the data furnished by Callon. We consider the factual data used in this report appropriate and sufficient for the purpose of preparing the estimates of reserves and future net revenues herein.

In summary, we consider the assumptions, data, methods and analytical procedures used in this report appropriate for the purpose hereof, and we have used all such methods and procedures that we consider necessary and appropriate to prepare the estimates of reserves herein. The proved reserves included herein were determined in conformance with the United States Securities and Exchange Commission (SEC) Modernization of Oil and Gas Reporting; Final Rule, including all references to Regulation S-X and Regulation S-K, referred to herein collectively as the “SEC Regulations.” In our opinion,

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Callon Petroleum Company

February 7, 2020

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the proved reserves presented in this report comply with the definitions, guidelines and disclosure requirements as required by the SEC regulations.

Future Production Rates

For wells currently on production, our forecasts of future production rates are based on historical performance data. If no production decline trend has been established, future production rates were held constant, or adjusted for the effects of curtailment where appropriate, until a decline in ability to produce was anticipated. An estimated rate of decline was then applied until depletion of the reserves. If a decline trend has been established, this trend was used as the basis for estimating future production rates.

Test data and other related information were used to estimate the anticipated initial production rates for those wells or locations that are not currently producing. For reserves not yet on production, sales were estimated to commence at an anticipated date furnished by Callon. Wells or locations that are not currently producing may start producing earlier or later than anticipated in our estimates due to unforeseen factors causing a change in the timing to initiate production. Such factors may include delays due to weather, the availability of rigs, the sequence of drilling, completing and/or recompleting wells and/or constraints set by regulatory bodies.

The future production rates from wells currently on production or wells or locations that are not currently producing may be more or less than estimated because of changes including, but not limited to, reservoir performance, operating conditions related to surface facilities, compression and artificial lift, pipeline capacity and/or operating conditions, producing market demand and/or allowables or other constraints set by regulatory bodies.

Hydrocarbon Prices

The hydrocarbon prices used herein are based on SEC price parameters using the average prices during the 12-month period prior to the “as of date” of this report, determined as the unweighted arithmetic averages of the prices in effect on the first-day-of-the-month for each month within such period, unless prices were defined by contractual arrangements. For hydrocarbon products sold under contract, the contract prices, including fixed and determinable escalations, exclusive of inflation adjustments, were used until expiration of the contract. Upon contract expiration, the prices were adjusted to the 12-month unweighted arithmetic average as previously described.

Callon furnished us with the above mentioned average prices in effect on December 31, 2019. These initial SEC hydrocarbon prices were determined using the 12-month average first-day-of-the-month benchmark prices appropriate to the geographic area where the hydrocarbons are sold. These benchmark prices are prior to the adjustments for differentials as described herein. The table below summarizes the “benchmark prices” and “price reference” used for the geographic area included in the report. In certain geographic areas, the price reference and benchmark prices may be defined by contractual arrangements.

The product prices which were actually used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions, and/or distance from market, referred to herein as “differentials.” The differentials used in the preparation of this report were furnished to us by Callon. The differentials furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of the data used by Callon to determine these differentials.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

Callon Petroleum Company

February 7, 2020

Page 7

In addition, the table below summarizes the net volume weighted benchmark prices adjusted for differentials and referred to herein as the “average realized prices.” The average realized prices shown in the table below were determined from the total future gross revenue before production taxes and the total net reserves for the geographic area and presented in accordance with SEC disclosure requirements for the geographic area included in the report.

Geographic Area	Product	Price Reference	Average Benchmark Prices	Average Realized Prices
United States	Oil/Condensate	WTI Cushing	$55.69/bbl	$54.66/bbl
	NGLs	WTI Cushing	$55.69/bbl*	$15.58/bbl
	Gas	Henry Hub	$2.58/MMBTU	$1.20/Mcf

*NGL Prices are calculated as a percentage of oil price.

The effects of derivative instruments designated as price hedges of oil and gas quantities are not reflected in our individual property evaluations.

Costs

Operating costs for the leases and wells in this report are based on the operating expense reports of Callon and include only those costs directly applicable to the leases or wells. The operating costs include a portion of general and administrative costs allocated directly to the leases and wells. For operated properties, the operating costs include an appropriate level of corporate general administrative and overhead costs. The operating costs for non-operated properties include the COPAS overhead costs that are allocated directly to the leases and wells under terms of operating agreements. No deduction was made for loan repayments, interest expenses, or exploration and development prepayments that were not charged directly to the leases or wells.

Development costs were furnished to us by Callon and are based on authorizations for expenditure for the proposed work or actual costs for similar projects. The development costs furnished to us were accepted as factual data and reviewed by us for their reasonableness; however, we have not conducted an independent verification of these costs. The estimated net cost of abandonment after salvage was included for properties where abandonment costs net of salvage were material. The estimates of the net abandonment costs furnished by Callon were accepted without independent verification.

The proved undeveloped reserves in this report have been incorporated herein in accordance with Callon’s plans to develop these reserves as of December 31, 2019. The implementation of Callon’s development plans as presented to us and incorporated herein is subject to the approval process adopted by Callon’s management. As the result of our inquiries during the course of preparing this report, Callon has informed us that the development activities included herein have been subjected to and received the internal approvals required by Callon’s management at the appropriate local, regional and/or corporate level. In addition to the internal approvals as noted, certain development activities may still be subject to specific partner AFE processes, Joint Operating Agreement (JOA) requirements or other administrative approvals external to Callon. Callon has provided written documentation supporting their commitment to proceed with the development activities as presented to us. Additionally, Callon has informed us that they are not aware of any legal, regulatory, or political obstacles that would significantly alter their plans. While

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February 7, 2020

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these plans could change from those under existing economic conditions as of December 31, 2019, such changes were, in accordance with rules adopted by the SEC, omitted from consideration in making this evaluation.

Current costs used by Callon were held constant throughout the life of the properties.

Standards of Independence and Professional Qualification

Ryder Scott is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1937. Ryder Scott is employee-owned and maintains offices in Houston, Texas; Denver, Colorado; and Calgary, Alberta, Canada. We have approximately eighty engineers and geoscientists on our permanent staff. By virtue of the size of our firm and the large number of clients for which we provide services, no single client or job represents a material portion of our annual revenue. We do not serve as officers or directors of any privately-owned or publicly-traded oil and gas company and are separate and independent from the operating and investment decision-making process of our clients. This allows us to bring the highest level of independence and objectivity to each engagement for our services.

Ryder Scott actively participates in industry-related professional societies and organizes an annual public forum focused on the subject of reserves evaluations and SEC regulations. Many of our staff have authored or co-authored technical papers on the subject of reserves related topics. We encourage our staff to maintain and enhance their professional skills by actively participating in ongoing continuing education.

Prior to becoming an officer of the Company, Ryder Scott requires that staff engineers and geoscientists have received professional accreditation in the form of a registered or certified professional engineer’s license or a registered or certified professional geoscientist’s license, or the equivalent thereof, from an appropriate governmental authority or a recognized self-regulating professional organization. Regulating agencies require that, in order to maintain active status, a certain amount of continuing education hours be completed annually, including an hour of ethics training. Ryder Scott fully supports this technical and ethics training with our internal requirement mentioned above.

We are independent petroleum engineers with respect to Callon. Neither we nor any of our employees have any financial interest in the subject properties and neither the employment to do this work nor the compensation is contingent on our estimates of reserves for the properties which were reviewed.

The results of this study, presented herein, are based on technical analysis conducted by teams of geoscientists and engineers from Ryder Scott. The professional qualifications of the undersigned, the technical person primarily responsible for overseeing the evaluation of the reserves information discussed in this report, are included as an attachment to this letter.

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Callon Petroleum Company

February 7, 2020

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Terms of Usage

The results of our third party study, presented in report form herein, were prepared in accordance with the disclosure requirements set forth in the SEC regulations and intended for public disclosure as an exhibit in filings made with the SEC by Callon.

Callon makes periodic filings on Form 10-K with the SEC under the 1934 Exchange Act. Furthermore, Callon has certain registration statements filed with the SEC under the 1933 Securities Actinto which any subsequently filed Form 10-K is incorporated by reference. We have consented to the incorporation by reference in the registration statements on Form S-3 and Form S-8of Callon, of the references to our name, as well as to the references to our third party report for Callon, which appears in the December 31, 2019 annual report on Form 10-Kof Callon. Our written consent for such use is included as a separate exhibit to the filings made with the SEC by Callon.

We have provided Callon with a digital version of the original signed copy of this report letter. In the event there are any differences between the digital version included in filingsmade by Callon and the original signed report letter, the original signed report letter shall control and supersede the digital version.

The data and work papers used in the preparation of this report are available for examination by authorized parties in our offices. Please contact us if we can be of further service.

Very truly yours,

RYDER SCOTT COMPANY, L.P.

TBPE Firm Registration No. F-1580

\s\ Val Rick Robinson

Val Rick Robinson, P.E.

TBPE License No. 105137

Managing Senior Vice President    [SEAL]

\s\ Michael F. Stell

Michael F. Stell, P.E.

TBPE License No. 56416

Associate Petroleum Engineer    [SEAL]

VRR-MFS (DCR)/pl

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 10

Professional Qualifications of Primary Technical Engineer

The conclusions presented in this report are the result of technical analysis conducted by teams of geoscientists and engineers from Ryder Scott Company, L.P. Mr. Val Rick Robinson was the primary technical person responsible for the estimate of the reserves, future production and income presented herein.

Mr. Robinson, an employee of Ryder Scott Company, L.P. (Ryder Scott) since 2006, is a Managing Senior Vice President responsible for coordinating and supervising staff and consulting engineers of the company in ongoing reservoir evaluation studies worldwide. Before joining Ryder Scott, Mr. Robinson served in a number of engineering positions with ExxonMobil Corporation. For more information regarding Mr. Robinson’s geographic and job specific experience, please refer to the Ryder Scott Company website at www.ryderscott.com.

Mr. Robinson earned a Bachelor of Science degree in Chemical Engineering from Brigham Young University in 2003 and is a licensed Professional Engineer in the State of Texas. He is also a member of the Society of Petroleum Engineers.

In addition to gaining experience and competency through prior work experience, the Texas Board of Professional Engineers requires a minimum of fifteen hours of continuing education annually, including at least one hour in the area of professional ethics, which Mr. Robinson fulfills. As part of his 2019 continuing education hours, Mr. Robinson attended 32 hours of formalized training including the 2019 RSC Reserves Conference and various professional society presentations covering such topics as the definitions and disclosure guidelines contained in the United States Securities and Exchange Commission Title 17, Code of Federal Regulations, Modernization of Oil and Gas Reporting, Final Rule released January 14, 2009 in the Federal Register, the SPE/WPC/AAPG/SPEE Petroleum Resources Management System, reservoir engineering, overviews of the various productive basins of North America, computer software, and professional ethics.

Based on his educational background, professional training and more than 16 years of practical experience in the estimation and evaluation of petroleum reserves, Mr. Robinson has attained the professional qualifications as a Reserves Estimator set forth in Article III of the “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information” promulgated by the Society of Petroleum Engineers as of February 19, 2007.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

PREAMBLE

On January 14, 2009, the United States Securities and Exchange Commission (SEC) published the “Modernization of Oil and Gas Reporting; Final Rule” in the Federal Register of National Archives and Records Administration (NARA). The “Modernization of Oil and Gas Reporting; Final Rule” includes revisions and additions to the definition section in Rule 4-10 of Regulation S-X, revisions and additions to the oil and gas reporting requirements in Regulation S-K, and amends and codifies Industry Guide 2 in Regulation S-K. The “Modernization of Oil and Gas Reporting; Final Rule”, including all references to Regulation S-X and Regulation S-K, shall be referred to herein collectively as the “SEC regulations”. The SEC regulations take effect for all filings made with the United States Securities and Exchange Commission as of December 31, 2009, or after January 1, 2010. Reference should be made to the full text under Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) for the complete definitions (direct passages excerpted in part or wholly from the aforementioned SEC document are denoted in italics herein).

Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations.All reserve estimates involve an assessment of the uncertainty relating the likelihood that the actual remaining quantities recovered will be greater or less than the estimated quantities determined as of the date the estimate is made. The uncertainty depends chiefly on the amount of reliable geologic and engineering data available at the time of the estimate and the interpretation of these data. The relative degree of uncertainty may be conveyed by placing reserves into one of two principal classifications, either proved or unproved. Unproved reserves are less certain to be recovered than proved reserves and may be further sub-classified as probable and possible reserves to denote progressively increasing uncertainty in their recoverability. Under the SEC regulations as of December 31, 2009, or after January 1, 2010, a company may optionally disclose estimated quantities of probable or possible oil and gas reserves in documents publicly filed with the SEC. The SEC regulations continue to prohibit disclosure of estimates of oil and gas resources other than reserves and any estimated values of such resources in any document publicly filed with the SEC unless such information is required to be disclosed in the document by foreign or state law as noted in §229.1202 Instruction to Item 1202.

Reserves estimates will generally be revised only as additional geologic or engineering data become available or as economic conditions change.

Reserves may be attributed to either natural energy or improved recovery methods. Improved recovery methods include all methods for supplementing natural energy or altering natural forces in the reservoir to increase ultimate recovery. Examples of such methods are pressure maintenance, natural gas cycling, waterflooding, thermal methods, chemical flooding, and the use of miscible and immiscible displacement fluids. Other improved recovery methods may be developed in the future as petroleum technology continues to evolve.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 2

Reserves may be attributed to either conventional or unconventional petroleum accumulations. Petroleum accumulations are considered as either conventional or unconventional based on the nature of their in-place characteristics, extraction method applied, or degree of processing prior to sale. Examples of unconventional petroleum accumulations include coalbed or coalseam methane (CBM/CSM), basin-centered gas, shale gas, gas hydrates, natural bitumen and oil shale deposits. These unconventional accumulations may require specialized extraction technology and/or significant processing prior to sale.

Reserves do not include quantities of petroleum being held in inventory.

Because of the differences in uncertainty, caution should be exercised when aggregating quantities of petroleum from different reserves categories.

RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(26) defines reserves as follows:

Reserves. Reserves are estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, the legal right to produce or a revenue interest in the production, installed means of delivering oil and gas or related substances to market, and all permits and financing required to implement the project.

Note to paragraph (a)(26): Reserves should not be assigned to adjacent reservoirs isolated by major, potentially sealing, faults until those reservoirs are penetrated and evaluated as economically producible. Reserves should not be assigned to areas that are clearly separated from a known accumulation by a non-productive reservoir (i.e., absence of reservoir, structurally low reservoir, or negative test results). Such areas may contain prospective resources (i.e., potentially recoverable resources from undiscovered accumulations).

PROVED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(22) defines proved oil and gas reserves as follows:

Proved oil and gas reserves. Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time.

(i) The area of the reservoir considered as proved includes:

(A) The area identified by drilling and limited by fluid contacts, if any, and

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES DEFINITIONS

Page 3

(B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data.

(ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty.

(iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty.

(iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when:

(A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and

(B) The project has been approved for development by all necessary parties and entities, including governmental entities.

(v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

As Adapted From:

RULE 4-10(a) of REGULATION S-X PART 210

UNITED STATES SECURITIES AND EXCHANGE COMMISSION (SEC)

and

2018 PETROLEUM RESOURCES MANAGEMENT SYSTEM (SPE-PRMS)

Sponsored and Approved by:

SOCIETY OF PETROLEUM ENGINEERS (SPE)

WORLD PETROLEUM COUNCIL (WPC)

AMERICAN ASSOCIATION OF PETROLEUM GEOLOGISTS (AAPG)

SOCIETY OF PETROLEUM EVALUATION ENGINEERS (SPEE)

SOCIETY OF EXPLORATION GEOPHYSICISTS (SEG)

SOCIETY OF PETROPHYSICISTS AND WELL LOG ANALYSTS (SPWLA)

EUROPEAN ASSOCIATION OF GEOSCIENTISTS & ENGINEERS (EAGE)

Reserves status categories define the development and producing status of wells and reservoirs. Reference should be made to Title 17, Code of Federal Regulations, Regulation S-X Part 210, Rule 4-10(a) and the SPE-PRMS as the following reserves status definitions are based on excerpts from the original documents (direct passages excerpted from the aforementioned SEC and SPE-PRMS documents are denoted in italics herein).

DEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(6) defines developed oil and gas reserves as follows:

Developed oil and gas reserves are reserves of any category that can be expected to be recovered:

(i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and

(ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well.

Developed Producing (SPE-PRMS Definitions)

While not a requirement for disclosure under the SEC regulations, developed oil and gas reserves may be further sub-classified according to the guidance contained in the SPE-PRMS as Producing or Non-Producing.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

PETROLEUM RESERVES STATUS DEFINITIONS AND GUIDELINES

Page 2

Developed Producing Reserves

Developed Producing Reserves are expected quantities to be recovered from completion intervals that are open and producing at the effective date of the estimate.

Improved recovery reserves are considered producing only after the improved recovery project is in operation.

Developed Non-Producing

Developed Non-Producing Reserves include shut-in and behind-pipe Reserves.

Shut-In

Shut-in Reserves are expected to be recovered from:

(1) completion intervals that are open at the time of the estimate but which have not yet started producing;

(2) wells which were shut-in for market conditions or pipeline connections; or

(3) wells not capable of production for mechanical reasons.

Behind-Pipe

Behind-pipe Reserves are expected to be recovered from zones in existing wells that will require additional completion work or future re-completion before start of production with minor cost to access these reserves.

In all cases, production can be initiated or restored with relatively low expenditure compared to the cost of drilling a new well.

UNDEVELOPED RESERVES (SEC DEFINITIONS)

Securities and Exchange Commission Regulation S-X §210.4-10(a)(31) defines undeveloped oil and gas reserves as follows:

Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion.

(i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances.

(ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances, justify a longer time.

(iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in paragraph (a)(2) of this section, or by other evidence using reliable technology establishing reasonable certainty.

RYDER SCOTT COMPANY PETROLEUM CONSULTANTS

XML

Commitments and Contingencies

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingencies

Commitments and 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 natural gas or produced water to be delivered, as of December 31, 2019.

	2020	2021	2022	2023	2024	2025 and Thereafter	Total
	(In thousands)
Operating leases	$12,423	$8,399	$4,363	$4,209	$4,110	$17,902	$51,406
Drilling rig contracts (1)	33,441	3,249	—	—	—	—	36,690
Delivery commitments (2)	9,563	13,437	10,980	11,553	12,417	39,298	97,248
Produced water disposal commitments (3)	14,947	14,968	11,933	4,387	1,570	1,840	49,645
Total	$70,374	$40,053	$27,276	$20,149	$18,097	$59,040	$234,989

(1) Drilling rig contracts 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.

(2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.

(3) Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

Operating leases

As of December 31, 2019, the Company had contracts for nine horizontal drilling rigs. The contract terms will end on various dates between January 2020 and May 2021.

Other commitments

In July 2019, the Company executed a crude oil sales contact that provides dedicated capacity on a new pipeline system that originates in Midland County, Texas and will have delivery points in several locations along the Gulf Coast. The Company will have a long-term 5,000 Bbls per day commitment for the term of the agreement and will apply applicable tariff rates to those quantities. Barrels may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In June 2019, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that originates in Midland, Texas and terminates in Houston, Texas. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our quantities committed that average 10,000 Bbls per day for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In January 2019, the Company executed a crude oil sales contract that provides further dedicated capacity on several pipeline systems that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas and will have delivery points in several locations along the Gulf Coast, providing the Company with the potential benefit of access to an international weighted average sales price. The Company will have a long-term 10,000 Bbls per day commitment for the term of the agreement, and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In August 2018, the Company executed a firm transportation agreement for dedicated capacity on a new pipeline system that will connect with a regional gathering system which currently transports oil volumes under long-term agreements from our properties in Howard and Ward Counties, Texas to multiple marketing points in the Permian Basin. Subject to completion of the new pipeline system, which will have delivery points in several locations along the Gulf Coast, the Company will have a long-term commitment that will apply applicable tariff rates to our 15,000 Bbls per day commitment for the term of the agreement. Barrels may be transported to multiple delivery points along the Gulf Coast and may include volumes produced by the Company and other third-party working, royalty, and overriding royalty interest owners whose volumes we market on their behalf.

In March 2018, the Company entered into a contract for dedicated fracturing and pump down perforating crews, which was effective on April 16, 2018 for a two-year period. The agreement was amended effective October 16, 2018 to reflect updated market conditions and to extend the contract expiration date to December 31, 2021.

XML

Leases

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Leases

eases

The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-

line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

Types of Leases

The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.

Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.

Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations.

Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations.

The tables below, which present the components of lease costs and 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, 2019.

	Year Ended December 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs		$92
Amortization of right-of-use assets (1)	82
Interest on lease liabilities (2)	10
Operating lease cost (3)	38,076
Impairment of Operating lease ROU assets (4)	16,209
Short-term lease cost (5)	3,640
Variable lease costs (6)	—
Total lease costs		$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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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 leases as of December 31, 2019.

	Year Ended December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$63,908
Current operating lease liabilities		$42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Financing leases:
Other property and equipment		$2,197
Accumulated depreciation	(82		)
Other property and equipment, net	2,115
Current financing lease liabilities		$1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	2,141

The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019.

	December 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4.3
Financing leases	2.1
Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	9.4	%

The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019.

	Operating Leases		Financing Leases
	(In thousands)
2020		$45,864		$1,475
2021	11,648		275
2022	4,363		234
2023	4,209		233
2024	4,110		38
Thereafter	17,902		—
Total lease payments	88,096		2,255
Less imputed interest	8,150		114
Total lease liabilities		$79,946		$2,141

Leases

eases

The Company determines if an arrangement is a lease at inception of the contract and, if the contract is determined to be a lease, classifies the lease as an operating or financing lease. The Company recognizes an operating or financing lease on its consolidated balance sheets as a lease liability, which represents the present value of the Company’s obligation to make lease payments arising from the lease, with a related ROU asset, which represents the Company’s right to use the underlying asset for the lease term. The Company’s operating leases typically do not provide an implicit interest rate, therefore, the Company utilizes its incremental borrowing rate to calculate the present value of the lease payments based on information available at inception of the contract.

Lease expense for operating leases is recognized on a straight-line basis over the lease term. Lease expense for financing leases is comprised of interest expense on the financing lease liability and the amortization of the associated ROU asset, which is recognized on a straight-

line basis over the lease term. Variable lease expense that is not dependent on an index or rate is not included in the operating or financing lease liability or ROU asset and is recognized in the period in which the obligation for those payments is incurred.

Types of Leases

The Company currently has leases associated with contracts for drilling rigs, office space, and the use of well equipment, vehicles, information technology infrastructure, and other office equipment, with the significant lease types described in more detail below.

Drilling Rigs. The Company enters into contracts for drilling rigs with third parties to support its development plan. These contracts are typically for one to three years and can be extended upon mutual agreement with the third party by providing written notice at least thirty days prior to the end of the primary contractual term. The Company exercises its discretion in choosing whether or not to extend these contracts on a drilling rig by drilling rig basis as a result of evaluating the conditions that exist at the time the contract expires, such as availability of drilling rigs and the Company’s development plan. The Company has determined that it cannot conclude with reasonable certainty that it will choose to extend the contract past its primary term. As such, the Company uses the primary term in its calculation of the lease liability and ROU asset. The Company classifies its drilling rigs as operating leases and capitalizes the costs of the drilling rigs to oil and gas properties.

Office Space. The Company leases office space from third parties for its corporate office and certain field locations. These leases have non-cancelable terms between one to fifteen years. The Company has determined that it cannot conclude with reasonable certainty that it will exercise any option to extend the contract past the non-cancelable term. As such, the Company uses the non-cancelable term in its calculation of the lease liability and ROU asset. The Company classifies its leases for office space as operating leases with the costs recognized as “General and administrative” in its consolidated statements of operations.

Well Equipment. The Company rents compressors from third parties to facilitate the flow of production from its drilling operations to market. These contracts range from less than one year to three years for the primary term and continue thereafter on a month to month basis subject to cancellation by either party with thirty days’ notice. The Company classifies the compressors as operating leases with a lease term equal to the primary term for those contracts that have a primary term greater than one year. After the primary term, each party has a substantive right to terminate the lease, therefore, enforceable rights and obligations do not exist subsequent to the primary term. For those contracts that are less than one year, the Company has concluded that they represent short-term operating leases and therefore, an operating lease liability and ROU asset is not recorded in the consolidated balance sheets. These lease payments are recognized as “Lease operating” in the Company’s statements of operations.

The tables below, which present the components of lease costs and 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, 2019.

	Year Ended December 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs		$92
Amortization of right-of-use assets (1)	82
Interest on lease liabilities (2)	10
Operating lease cost (3)	38,076
Impairment of Operating lease ROU assets (4)	16,209
Short-term lease cost (5)	3,640
Variable lease costs (6)	—
Total lease costs		$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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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 leases as of December 31, 2019.

	Year Ended December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$63,908
Current operating lease liabilities		$42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Financing leases:
Other property and equipment		$2,197
Accumulated depreciation	(82		)
Other property and equipment, net	2,115
Current financing lease liabilities		$1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	2,141

The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019.

	December 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4.3
Financing leases	2.1
Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	9.4	%

The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019.

	Operating Leases		Financing Leases
	(In thousands)
2020		$45,864		$1,475
2021	11,648		275
2022	4,363		234
2023	4,209		233
2024	4,110		38
Thereafter	17,902		—
Total lease payments	88,096		2,255
Less imputed interest	8,150		114
Total lease liabilities		$79,946		$2,141

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Summary of Significant Accounting Policies (Policies)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Basis of Presentation and Principles of Consolidation

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved 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, 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

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

Accounts Receivable, Net

Accounts Receivable, Net

Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all period presented.

Concentration of Credit Risk and Major Customers

The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.

The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity.

Oil and Natural Gas Properties

Oil and Natural Gas Properties

The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 

Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship.

Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on 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 unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.

Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as a write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did not recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. 

Other Property and Equipment

Other Property and Equipment

The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.

Deferred Financing Costs

Deferred Financing Costs

Deferred financing costs associated with the Company’s senior notes are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-line method over the terms of the related senior notes. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility.

Asset Retirement Obligations

Asset Retirement Obligations

The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information.

Derivative Instruments

Derivative Instruments

The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes.

The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which

the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion.

Revenue Recognition

Revenue Recognition

The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “Note 3 - Revenue Recognition” for further discussion.

Income Taxes

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. As of December 31, 2019 and 2018, the Company did not have a valuation allowance against its deferred tax assets. See “Note 12 - Income Taxes” for further discussion.

Share-Based Compensation

Share-Based Compensation

The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below.

RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years). 

Cash SARs. Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. 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 will expire between one and seven years, depending on the date of grant.

Earnings per Share

Earnings per Share

The Company’s basic net income attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. See “Note 6 - Earnings Per Share” for further discussion.

Industry Segment and Geographic Information

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of crude oil, NGLs, and natural gas. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.

Accounting Standards Updates

Recently Adopted Accounting Standards

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”).

Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

Upon adoption, the Company implemented policy elections and practical expedients which include the following:

• package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance

• excluding ROU assets and lease liabilities for leases with terms that are less than one year;

• combining lease and non-lease components and accounting for them as a single lease (elected by asset class);

• excluding land easements that existed or expired prior to adoption; and

• policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.

Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion.

Recently Issued ASUs

None that are expected to have a material impact on our financial statements.

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Derivative Instruments and Hedging Activities (Schedule of Outstanding Oil and Natural Gas Derivative Contracts) (Details) - Forecast - Not Designated as Hedging Instrument	12 Months Ended
	Dec. 31, 2021 MMBTU $ / bbl $ / MMBTU bbl	Dec. 31, 2020 MMBTU $ / bbl $ / MMBTU bbl
Commodity - Oil | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,303,900
Weighted average price (in dollars per share)	0	55.19
Commodity - Oil | Short
Derivative [Line Items]
Total volume (Bbls) | bbl	4,825,300	1,674,450
Weighted average price (in dollars per share)	63.62	75.98
Commodity - Oil | Short | Swap contracts
Derivative [Line Items]
Total volume (Bbls) | bbl	0	2,196,000
Weighted average price (in dollars per share)	0	56.06
Commodity - Oil | Put option | Short | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	42.50
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	13,176,000
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	65.28
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	45.08
Commodity - Oil | Collar contracts with short puts (WTI, three-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	55.38
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	837,500
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	70.00
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	50.00
Commodity - Oil | Collar contracts with short puts (Brent ICE, three-way collars) | Put option | Long
Derivative [Line Items]
Weighted average price (in dollars per share) | $ / bbl	0	58.24
Commodity - Oil | Oil contracts (Midland basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	4,015,100	8,476,700
Weighted average price (in dollars per share) | $ / bbl	0.40
Weighted average price (in dollars per share) | $ / bbl		(1.47)
Commodity - Oil | Oil contracts (Argus Houston MEH basis differential)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	1,439,205
Weighted average price (in dollars per share)	0	2.40
Commodity - Oil | Oil contracts (Argus Houston MEH swaps)
Derivative [Line Items]
Total volume (Bbls) | bbl	0	504,500
Weighted average price (in dollars per share)	0	58.22
Commodity - Natural gas | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.48
Total volume (MMBtu) | MMBTU	0	3,660,000
Commodity - Natural gas | Call option | Swap contracts
Derivative [Line Items]
Weighted average price (in dollars per share)	3.09	3.50
Total volume (MMBtu) | MMBTU	7,300,000	12,078,000
Commodity - Natural gas | Collar contracts (two-way collars)
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	3,660,000
Commodity - Natural gas | Collar contracts (two-way collars) | Long
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.50
Commodity - Natural gas | Collar contracts (two-way collars) | Call option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.75
Commodity - Natural gas | Collar contracts (two-way collars) | Put option | Short
Derivative [Line Items]
Weighted average price (in dollars per share)	0	2.00
Commodity - Natural gas | Waha basis differential | Swap contracts
Derivative [Line Items]
Total volume (MMBtu) | MMBTU	0	21,596,000
Weighted average price (in dollars per share)	0	(1.04)

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Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Capitalized Costs) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and Gas Exploration and Production Industries Disclosures [Abstract]
Evaluated properties	$ 7,203,482	$ 4,585,020
Unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties	9,189,606	5,989,533
Less accumulated depreciation, depletion, amortization and impairment	(2,520,488)	(2,270,675)
Total oil and natural gas properties, net	$ 6,669,118	$ 3,718,858

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Commitments and Contingencies (Contractual Obligations) (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Contractual Obligations
2020	$ 70,374
2021	40,053
2022	27,276
2023	20,149
2024	18,097
2025 and Thereafter	59,040
Total	234,989
Delivery commitments
Contractual Obligations
2020	9,563
2021	13,437
2022	10,980
2023	11,553
2024	12,417
2025 and Thereafter	39,298
Total	97,248
Produced water disposal commitments
Contractual Obligations
2020	14,947
2021	14,968
2022	11,933
2023	4,387
2024	1,570
2025 and Thereafter	1,840
Total	49,645
Operating leases
Contractual Obligations
2020	12,423
2021	8,399
2022	4,363
2023	4,209
2024	4,110
2025 and Thereafter	17,902
Total	51,406
Drilling rig contracts
Contractual Obligations
2020	33,441
2021	3,249
2022	0
2023	0
2024	0
2025 and Thereafter	0
Total	$ 36,690

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Derivative Instruments and Hedging Activities (Contingent Consideration Arrangement) (Details) $ in Thousands	Jan. 31, 2020 USD ($)	Dec. 31, 2019 USD ($) $ / bbl
Divestiture, Ranger
Derivative [Line Items]
Divestiture Date Fair Value		$ 8,512
Payment to be presented in cash flows from financing activities		8,500
Remaining potential settlements in future years		41,500
Merger, Contingent ExL Consideration
Derivative [Line Items]
Acquisition Date Fair Value		$ (69,171)
Merger, Contingent ExL Consideration | Subsequent Event
Derivative [Line Items]
Contingent payment made	$ 50,000
Remaining potential settlements in future years	$ 25,000
Pending Settlement 2019
Derivative [Line Items]
Threshold | $ / bbl		65
Pending Settlement 2019 | Divestiture, Ranger
Derivative [Line Items]
Contingent Receipt - Annual		$ 0
Contingent Receipt - Annual		$ 0
Pending Settlement 2019 | Merger, Contingent ExL Consideration
Derivative [Line Items]
Threshold | $ / bbl		50.00
Contingent Payment - Annual		$ (50,000)
Pending Settlement 2019 | Minimum
Derivative [Line Items]
Threshold | $ / bbl		60
Pending Settlement 2019 | Maximum
Derivative [Line Items]
Threshold | $ / bbl		65
Remaining Potential Settlements 2020-2021
Derivative [Line Items]
Threshold | $ / bbl		65
Remaining Potential Settlements 2020-2021 | Divestiture, Ranger
Derivative [Line Items]
Contingent Receipt - Annual		$ 9,000
Contingent Receipt - Annual		20,833
Remaining Contingent Receipt - Aggregate Limit		$ 60,000
Remaining Potential Settlements 2020-2021 | Merger, Contingent ExL Consideration
Derivative [Line Items]
Threshold | $ / bbl		50.00
Contingent Payment - Annual		$ (50,000)
Remaining Contingent Payments - Aggregate Limit		$ (75,000)
Remaining Potential Settlements 2020-2021 | Minimum
Derivative [Line Items]
Threshold | $ / bbl		60
Remaining Potential Settlements 2020-2021 | Maximum
Derivative [Line Items]
Threshold | $ / bbl		65

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Acquisitions and Divestitures (Narrative) (Details) $ / shares in Units, shares in Millions						3 Months Ended								4 Months Ended	11 Months Ended	12 Months Ended
	Dec. 31, 2019 USD ($)	Dec. 20, 2019 USD ($) $ / shares shares	Aug. 31, 2018 USD ($) a	Jun. 05, 2017 USD ($) a	Feb. 13, 2017 USD ($) a	Dec. 31, 2019 USD ($)	Sep. 30, 2019 USD ($)	Jun. 30, 2019 USD ($) a	Mar. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Sep. 30, 2018 USD ($)	Jun. 30, 2018 USD ($)	Mar. 31, 2018 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)	Jun. 07, 2018 USD ($)	May 19, 2017 USD ($)	Oct. 03, 2016 USD ($)
Business Acquisition [Line Items]
Total operating revenues						$ 196,095,000	$ 155,378,000	$ 167,052,000	$ 153,047,000	$ 161,895,000	$ 161,214,000	$ 137,075,000	$ 127,440,000			$ 671,572,000	$ 587,624,000	$ 366,474,000
Total operating expenses																498,914,000	328,094,000	225,028,000
Proceeds from sales of working interest																$ 294,417,000	$ 9,009,000	$ 20,525,000
6.375% Senior Notes due 2026
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%					6.375%				6.375%				6.375%		6.375%	6.375%
6.375% Senior Notes due 2026 | Unsecured debt
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%					6.375%										6.375%			6.375%
Debt instrument principal amount																			$ 400,000,000.0
6.125% Senior Notes due 2024
Business Acquisition [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%					6.125%									6.125%	6.125%		6.125%		6.125%	6.125%
Debt instrument principal amount																				$ 200,000,000.0	$ 400,000,000.0
Carrizo
Business Acquisition [Line Items]
Acquisition related costs																$ 15,600,000
Carrizo | 8.875% Preferred Stock [Member]
Business Acquisition [Line Items]
Preferred stock cumulative cash dividends rate		8.875%
Certain Non-core Assets in the Midland Basin
Business Acquisition [Line Items]
Disposal group, consideration								244,900,000
Disposal group, potential contingency payments								$ 60,000,000.0
Working interest								66.00%
Disposal group, area of land | a								9,850
Carrizo
Business Acquisition [Line Items]
Exchange ratio (in shares)	1.75	1.75				1.75										1.75
Shares of common stock issued in acquisition (in shares) | shares		168.2
Shares of common stock issued in acquisition (in dollars per share) | $ / shares		$ 4.55
Fair value of the Company’s common stock issued		$ 765,373,000
Total operating revenues	$ 28,600,000
Total operating expenses	7,000,000.0
Acquisition related costs																$ 58,800,000
Restructuring costs																74,400,000
Total consideration		$ 765,373,000
Carrizo | Accounts Payable and Accrued Liabilities
Business Acquisition [Line Items]
Restructuring accruals	$ 52,400,000					$ 52,400,000										52,400,000
Carrizo | Acquisition & Integration
Business Acquisition [Line Items]
Restructuring costs																45,600,000
Carrizo | Severance costs
Business Acquisition [Line Items]
Restructuring costs																$ 28,800,000
Cimarex Energy Company
Business Acquisition [Line Items]
Total operating revenues														$ 27,300,000
Total operating expenses														$ 9,900,000
Total consideration			$ 539,500,000
Gas and oil area, developed and undeveloped, net | a			28,000
Monarch and Wildhorse
Business Acquisition [Line Items]
Total consideration													$ 37,800,000
Wildhorse and Spur
Business Acquisition [Line Items]
Total consideration										$ 87,900,000
Delaware Basin
Business Acquisition [Line Items]
Total operating revenues															$ 36,100,000
Total operating expenses															$ 8,500,000
Working interest					82.00%
Total consideration				$ 52,000,000.0	$ 646,600,000
Gas and oil area, developed and undeveloped, net | a				2,488	16,688
Gas and oil area, developed and undeveloped, gross | a				7,031	29,175
Net revenue interest					75.00%

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Accounts Payable and Accrued Liabilities (Tables)

12 Months Ended

Dec. 31, 2019

Payables and Accruals [Abstract]

Schedule of Accrued Liabilities

	As of December 31,
	2019		2018
	(In thousands)
Accounts payable		$238,758		$83,412
Revenues payable	145,816		94,114
Accrued capital expenditures	61,950		83,658
Accrued interest	36,295		24,665
Accrued severance (1)	28,803		—
Total accounts payable and accrued liabilities		$511,622		$285,849

(1)    See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

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Summary of Significant Accounting Policies (Major Customers) (Details) - Revenue Benchmark - Customer Concentration Risk	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Rio Energy International, Inc.
Product Information [Line Items]
Concentration risk, percentage	26.00%	28.00%	17.00%
Enterprise Crude Oil, LLC
Product Information [Line Items]
Concentration risk, percentage	19.00%	14.00%	18.00%
Plains Marketing, L.P.
Product Information [Line Items]
Concentration risk, percentage	15.00%	21.00%	29.00%
Shell Trading Company
Product Information [Line Items]
Concentration risk, percentage	10.00%

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Share-Based Compensation (Cash-Settled RSU Awards) (Details) - Cash-settleable RSU awards - $ / shares shares in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash-Settled RSU Awards
Unvested at the beginning of the period (in shares)	678	625	734
Granted (in shares)	424	348	283
Vested (in shares)	(164)	(276)	(379)
Forfeited (in shares)	(83)	(19)	(13)
Unvested at the end of the period (in shares)	855	678	625
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 12.36	$ 9.88	$ 8.87
Granted, grant date fair value per share (usd per share)	8.14	14.16	12.13
Vested, grant date fair value per share (usd per share)	12.02	9.04	9.61
Forfeited, grant date fair value per share (usd per share)	11.58	12.05	9.54
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 10.41	$ 12.36	$ 9.88

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Leases (Narrative) (Details)	Dec. 31, 2019
Offices | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Offices | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	15 years
Wells Equipment | Minimum
Lessee, Lease, Description [Line Items]
Term of contract	1 year
Wells Equipment | Maximum
Lessee, Lease, Description [Line Items]
Term of contract	3 years

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Leases (Maturities) (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Operating Leases
2020	$ 45,864
2021	11,648
2022	4,363
2023	4,209
2024	4,110
Thereafter	17,902
Total lease payments	88,096
Less imputed interest	8,150
Total	79,946
Financing Leases
2020	1,475
2021	275
2022	234
2023	233
2024	38
Thereafter	0
Total lease payments	2,255
Less imputed interest	114
Total lease liabilities	$ 2,141

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Share-Based Compensation (Schedule of Share-based Compensation Expense) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	$ 14,322	$ 9,460	$ 10,225
Share-based compensation expense - Liability-based	1,464	336	4,294
Settled share-based awards	3,024	0	6,351
Share-based compensation - capitalized oil and gas properties	4,700	3,400	3,200
General and Administrative Expense
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation	11,100	6,400	5,000
CFO
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Settled share-based awards			6,400
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	14,322	9,460	10,225
Share-based compensation expense - Liability-based	0	0	0
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	0	0	0
Share-based compensation expense - Liability-based	1,021	336	4,294
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation expense - Equity-based	0	0	0
Share-based compensation expense - Liability-based	$ 443	$ 0	$ 0

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Supplemental Quarterly Financial Information (Unaudited) (Summary) (Details) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Total operating revenues	$ 196,095	$ 155,378	$ 167,052	$ 153,047	$ 161,895	$ 161,214	$ 137,075	$ 127,440	$ 671,572	$ 587,624	$ 366,474
Income from operations	18,380	52,544	58,509	43,225	58,333	72,811	67,400	60,986	172,658	259,530	141,446
Net income (loss)	(23,543)	55,834	55,180	(19,543)	156,194	37,931	50,474	55,761	67,928	300,360	120,424
Income (loss) available to common stockholders	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 55,627	$ 293,065	$ 113,129
Income (loss) available to common stockholders per common share
Basic (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Diluted (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56

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Property and Equipment, Net (Narrative) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment [Abstract]
Internal costs capitalized, Oil and Gas producing activities	$ 36.2	$ 28.0	$ 20.3
Capitalized interest	$ 78.5	$ 56.2	$ 33.8

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Acquisitions and Divestitures (Assets Acquired and Liabilities Assumed) (Details) - Carrizo $ in Thousands	Dec. 20, 2019 USD ($)
Consideration:
Fair value of the Company’s common stock issued	$ 765,373
Total consideration	765,373
Liabilities:
Accounts payable	37,657
Revenues and royalties payable	52,449
Operating lease liabilities - current	29,924
Fair value of derivatives - current	61,015
Other current liabilities	82,084
Long-term debt	1,984,135
Operating lease liabilities - non-current	30,070
Asset retirement obligation	26,151
Fair value of derivatives - non-current	26,960
Other long-term liabilities	17,260
Common stock warrants	10,029
Total liabilities assumed	2,357,734
Assets:
Accounts receivable, net	48,479
Fair value of derivatives - current	17,451
Other current assets	4,945
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	159,320
Operating lease right-of-use-assets	59,994
Other long term assets	2,578
Total assets acquired	3,123,107
Evaluated properties
Assets:
Oil and natural gas properties	2,133,280
Unevaluated properties
Assets:
Oil and natural gas properties	$ 682,928

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Consolidated Balance Sheets - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Current assets:
Cash and cash equivalents	$ 13,341	$ 16,051
Accounts receivable, net	209,463	131,720
Fair value of derivatives	26,056	65,114
Other current assets	19,814	9,740
Total current assets	268,674	222,625
Oil and natural gas properties, full cost accounting method:
Evaluated properties, net	4,682,994	2,314,345
Unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties, net	6,669,118	3,718,858
Operating lease right-of-use assets	63,908
Other property and equipment, net	35,253	21,901
Deferred tax asset	115,720	0
Deferred financing costs	22,233	6,087
Fair value of derivatives	9,216	0
Other assets, net	10,716	9,702
Total assets	7,194,838	3,979,173
Current liabilities:
Accounts payable and accrued liabilities	511,622	285,849
Operating lease liabilities	42,858
Fair value of derivatives	71,197	10,480
Other current liabilities	26,570	18,587
Total current liabilities	652,247	314,916
Long-term debt	3,186,109	1,189,473
Operating lease liabilities	37,088
Asset retirement obligations	48,860	10,405
Deferred tax liability	0	9,564
Fair value of derivatives	32,695	7,440
Other long-term liabilities	14,531	2,167
Total liabilities	3,971,530	1,533,965
Commitments and contingencies
Stockholders’ equity:
Preferred stock, series A cumulative, $0.01 par value and $50.00 liquidation preference, 2,500,000 shares authorized: 0 and 1,458,948 shares outstanding, respectively	0	15
Common stock, $0.01 par value, 525,000,000 and 300,000,000 shares authorized, respective; 396,600,022 and 227,582,575 shares outstanding, respectively	3,966	2,276
Capital in excess of par	3,198,076	2,477,278
Retained earnings (Accumulated deficit)	21,266	(34,361)
Total stockholders’ equity	3,223,308	2,445,208
Total liabilities and stockholders’ equity	$ 7,194,838	$ 3,979,173

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Borrowings (Senior Secured Revolving Credit Facility) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2019	May 01, 2019	May 25, 2017	May 19, 2017	Oct. 03, 2016
Line of Credit Facility [Line Items]
Loss on extinguishment of debt	$ 4,881,000	$ 0	$ 0
Borrowings outstanding	3,185,000,000	1,200,000,000
Senior Secured Revolving Credit Facility | Secured Debt
Line of Credit Facility [Line Items]
Maximum borrowing capacity						$ 2,000,000,000.0
Current borrowing capacity					$ 1,100,000,000
Loss on extinguishment of debt	$ 4,900,000
Borrowings outstanding		200,000,000
6.25% Senior Notes due 2023
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%			6.25%				6.25%
Borrowings outstanding	$ 650,000,000	0
6.125% Senior Notes due 2024
Line of Credit Facility [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%				6.125%	6.125%
Borrowings outstanding	$ 600,000,000	$ 600,000,000
New Credit Facility
Line of Credit Facility [Line Items]
Maximum borrowing capacity				$ 5,000,000,000.0
Current borrowing capacity	2,500,000,000
Increase limit	2,000,000,000.0
Borrowings outstanding	$ 1,285,000,000
Leverage ratio	300.00%
Letters of credit outstanding	$ 17,700,000
Interest rate at period end (as a percent)	3.56%
New Credit Facility | Minimum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee (as a percent)	0.375%
New Credit Facility | Maximum
Line of Credit Facility [Line Items]
Unused capacity, commitment fee (as a percent)	0.50%
New Credit Facility | Base Rate | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.25%
New Credit Facility | Base Rate | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.25%
New Credit Facility | Federal Funds Rate
Line of Credit Facility [Line Items]
Debt instrument interest rate	0.50%
New Credit Facility | LIBOR
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.00%
New Credit Facility | Eurodollar | Minimum
Line of Credit Facility [Line Items]
Debt instrument interest rate	1.25%
New Credit Facility | Eurodollar | Maximum
Line of Credit Facility [Line Items]
Debt instrument interest rate	2.25%

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Consolidated Statements of Cash Flows - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Cash flows from operating activities:
Net income	$ 67,928	$ 300,360	$ 120,424
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation, depletion and amortization	245,936	185,605	118,728
Amortization of non-cash debt related items	2,907	2,483	2,150
Income Tax Expense (Benefit)	35,301	8,110	1,273
(Gain) loss on derivative contracts	62,109	(48,544)	18,901
Cash paid for commodity derivative settlements, net	(3,789)	(27,272)	(8,472)
(Gain) loss on sale of other property and equipment	(90)	(144)	62
Non-cash loss on early extinguishment of debt	4,881	0	0
Non-cash expense related to equity share-based awards	9,767	6,289	8,254
Change in the fair value of liability share-based awards	1,624	375	3,288
Payments to settle asset retirement obligations	(4,148)	(1,469)	(2,047)
Payments for cash-settled restricted stock unit awards	(1,425)	(4,990)	(13,173)
Changes in current assets and liabilities:
Accounts receivable	(35,071)	(17,351)	(44,495)
Other current assets	(4,166)	(7,601)	108
Current liabilities	86,438	74,311	30,947
Other	8,114	(2,508)	(6,057)
Net cash provided by operating activities	476,316	467,654	229,891
Cash flows from investing activities:
Capital expenditures	(640,540)	(611,173)	(419,839)
Acquisitions	(42,266)	(718,793)	(718,456)
Acquisition deposit	0	0	45,238
Proceeds from sales of assets	294,417	9,009	20,525
Additions to other assets	0	(3,100)	0
Net cash used in investing activities	(388,389)	(1,324,057)	(1,072,532)
Cash flows from financing activities:
Borrowings on senior secured revolving credit facility	2,455,900	500,000	25,000
Payments on senior secured revolving credit facility	(895,500)	(325,000)	0
Payment to terminate Prior Credit Facility	(475,400)	0	0
Repayment of Carrizo’s senior secured revolving credit facility	(853,549)	0	0
Redemption of preferred stock	(73,017)	0	0
Premium on the issuance of 6.125% Senior Notes due 2024	0	0	8,250
Issuance of common stock	0	287,988	0
Payment of preferred stock dividends	(3,997)	(7,295)	(7,295)
Payment of deferred financing costs	(22,480)	(9,430)	(7,194)
Tax withholdings related to restricted stock units	(2,195)	(1,804)	(1,118)
Net cash provided by (used in) financing activities	(90,637)	844,459	217,643
Net change in cash and cash equivalents	(2,710)	(11,944)	(624,998)
Balance, beginning of period	16,051	27,995	652,993
Balance, end of period	13,341	16,051	27,995
6.125% Senior Notes due 2024
Cash flows from financing activities:
Issuance of senior unsecured notes	0	0	200,000
6.375% Senior Notes due 2026
Cash flows from financing activities:
Issuance of senior unsecured notes	0	400,000	0
Carrizo
Cash flows from financing activities:
Redemption of preferred stock	$ (220,399)	$ 0	$ 0

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Asset Retirement Obligations (Tables)

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation [Abstract]

Schedule of Change in Asset Retirement Obligation

The table below summarizes the activity for the Company’s asset retirement obligations:

	Years Ended December 31,
	2019			2018
	(In thousands)
Asset retirement obligations, beginning of period		$14,292			$6,020
Accretion expense	945			874
Liabilities incurred	615			973
Increase due to acquisition of oil and gas properties	26,107			570
Liabilities settled	(3,394		)	(1,288		)
Dispositions	(1,776		)	(614		)
Revisions to estimates	12,944			7,757
Asset retirement obligations, end of period	49,733			14,292
Less: Current asset retirement obligations	(873		)	(3,887		)
Non-current asset retirement obligations		$48,860			$10,405

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Property and Equipment, Net (Tables)

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Schedule of Property and Equipment

As of December 31, 2019 and 2018, total property and equipment, net consisted of the following:

	As of December 31,
	2019			2018
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Accumulated depreciation, depletion, amortization and impairments	(2,520,488		)	(2,270,675		)
Net evaluated oil and natural gas properties	4,682,994			2,314,345
Unevaluated properties
Unevaluated leasehold and seismic costs	1,843,725			1,316,190
Capitalized interest	142,399			88,323
Total unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties, net		$6,669,118			$3,718,858
Other property and equipment		$67,202			$38,463
Accumulated depreciation	(31,949		)	(16,562		)
Other property and equipment, net		$35,253			$21,901

Schedule of Capitalized Costs of Unproved Properties Excluded from Amortization

Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following:

	2019		2018		2017		2016		Total
	(In thousands)
Acquisition costs		$682,413		$383,238		$577,959		$115,833		$1,759,443
Exploration costs	43,174		22,384		18,724		—		84,282
Capitalized interest	78,492		56,151		7,756		—		142,399
Total unevaluated properties		$804,079		$461,773		$604,439		$115,833		$1,986,124

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Fair Value Measurements (Tables)

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Summary of Fair Value of Financial Instruments at Carrying and Fair Value

The carrying amount of borrowings outstanding under the Credit Facility approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior 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.

	2019				2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes		$650,000		$658,125		$—		$—
6.125% Senior Notes	600,000		611,130		600,000		558,000
8.25% Senior Notes	250,000		256,250		—		—
6.375% Senior Notes	400,000		405,424		400,000		372,000
Total		$1,900,000		$1,930,929		$1,000,000		$930,000

Fair Value of Assets Measured on Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018:

	December 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$9,338			$—
Contingent consideration arrangements	—		25,934			—
Liabilities
Commodity derivative instruments	—		(34,132		)	—
Contingent consideration arrangements	—		(69,760		)	—
Total net assets (liabilities)		$—		($68,620	)		$—
	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$65,114			$—
Liabilities
Commodity derivative instruments	—		(17,920		)	—
Total net liabilities (liabilities)		$—		$47,194			$—

Fair Value of Liabilities Measured on Recurring Basis

The following tables present the Company’s assets and liabilities measured at fair value on a recurring basis as of December 31, 2019 and 2018:

	December 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$9,338			$—
Contingent consideration arrangements	—		25,934			—
Liabilities
Commodity derivative instruments	—		(34,132		)	—
Contingent consideration arrangements	—		(69,760		)	—
Total net assets (liabilities)		$—		($68,620	)		$—
	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$65,114			$—
Liabilities
Commodity derivative instruments	—		(17,920		)	—
Total net liabilities (liabilities)		$—		$47,194			$—

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Fair Value Measurements

12 Months Ended

Dec. 31, 2019

Fair Value Disclosures [Abstract]

Fair Value Measurements

Fair Value Measurements

Accounting guidelines for measuring fair value establish a three-level valuation hierarchy for disclosure of fair value measurements. The valuation hierarchy categorizes assets and liabilities measured at fair value into one of three different levels depending on the observability of the inputs employed in the measurement. The three levels are defined as follows:

Level 1 – Observable inputs such as quoted prices in active markets at the measurement date for identical, unrestricted assets or liabilities.

Level 2 – Other inputs that are observable 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 which the Company makes its own assumptions about how market participants would price the assets and liabilities.

Fair value of financial instruments

Cash, cash equivalents, and 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 Credit Facility approximate fair value as the borrowings bear interest at variable rates and are reflective of market rates. The following table presents the principal amounts of the Company’s senior 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.

	2019				2018
	Principal Amount		Fair Value		Principal Amount		Fair Value
	(In thousands)
6.25% Senior Notes		$650,000		$658,125		$—		$—
6.125% Senior Notes	600,000		611,130		600,000		558,000
8.25% Senior Notes	250,000		256,250		—		—
6.375% Senior Notes	400,000		405,424		400,000		372,000
Total		$1,900,000		$1,930,929		$1,000,000		$930,000

Assets and liabilities measured at fair value on a 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:

Commodity derivative instruments. The fair value of commodity derivative instruments is derived using a 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. As the inputs in the model are substantially observable over the term of the commodity derivative contract and there is a wide availability of quoted market prices for similar commodity derivative contracts, the Company designates its commodity derivative instruments as Level 2 within the fair value hierarchy. See “Note 8 - Derivative Instruments and Hedging Activities” for further discussion.

Contingent consideration arrangements - embedded derivative financial instruments. The embedded options within the 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 as of December 31, 2019 and 2018:

	December 31, 2019
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$9,338			$—
Contingent consideration arrangements	—		25,934			—
Liabilities
Commodity derivative instruments	—		(34,132		)	—
Contingent consideration arrangements	—		(69,760		)	—
Total net assets (liabilities)		$—		($68,620	)		$—
	December 31, 2018
	Level 1		Level 2			Level 3
	(In thousands)
Assets
Commodity derivative instruments		$—		$65,114			$—
Liabilities
Commodity derivative instruments	—		(17,920		)	—
Total net liabilities (liabilities)		$—		$47,194			$—

Assets and Liabilities Measured at Fair Value on a Nonrecurring Basis

Acquisitions. The fair value of 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 the income approach based on inputs that are not observable in the market 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, oil and natural gas forward prices, and a risk adjusted discount rate. See “Note 4 - Acquisitions and Divestitures” for additional discussion.

Asset retirement obligations. The Company measures the fair value of asset retirement obligations as of the date a well begins drilling or when production equipment and facilities are installed using a discounted cash flow model based on inputs that are not observable in the market and therefore are designated as Level 3 within the valuation hierarchy. Significant inputs to the fair value measurement of asset retirement obligations include estimates of the costs of plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land as well as estimates of the economic lives of the oil and gas wells and future inflation rates. See “Note 14 - Asset Retirement Obligations” for additional discussion.

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Property and Equipment, Net

12 Months Ended

Dec. 31, 2019

Property, Plant and Equipment [Abstract]

Property and Equipment, Net

Property and Equipment, Net

As of December 31, 2019 and 2018, total property and equipment, net consisted of the following:

	As of December 31,
	2019			2018
Oil and natural gas properties, full cost accounting method	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Accumulated depreciation, depletion, amortization and impairments	(2,520,488		)	(2,270,675		)
Net evaluated oil and natural gas properties	4,682,994			2,314,345
Unevaluated properties
Unevaluated leasehold and seismic costs	1,843,725			1,316,190
Capitalized interest	142,399			88,323
Total unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties, net		$6,669,118			$3,718,858
Other property and equipment		$67,202			$38,463
Accumulated depreciation	(31,949		)	(16,562		)
Other property and equipment, net		$35,253			$21,901

The Company capitalized internal costs of employee compensation and benefits, including stock-based compensation, directly associated with acquisition, exploration and development activities totaling $36.2 million, $28.0 million and $20.3 million for the years ended December 31, 2019, 2018 and 2017, respectively. The Company capitalized interest costs to unproved properties totaling $78.5 million, $56.2 million and $33.8 million for the years ended December 31, 2019, 2018 and 2017, respectively.

Unevaluated property costs not subject to amortization as of December 31, 2019 consisted of the following:

	2019		2018		2017		2016		Total
	(In thousands)
Acquisition costs		$682,413		$383,238		$577,959		$115,833		$1,759,443
Exploration costs	43,174		22,384		18,724		—		84,282
Capitalized interest	78,492		56,151		7,756		—		142,399
Total unevaluated properties		$804,079		$461,773		$604,439		$115,833		$1,986,124

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Supplemental Quarterly Financial Information (Unaudited) Supplemental Quarterly Financial Information (Unaudited) (Additional Information) (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Quarterly Financial Information Disclosure [Abstract]
Gain (loss) on derivatives	$ (30,700)	$ 21,800	$ 14,000	$ (67,300)	$ 103,900	$ (34,300)	$ (16,600)	$ (62,109)	$ 48,544	$ (18,901)
Non-cash loss on early extinguishment of debt	4,900							4,881	0	0
Merger and integration expenses	$ 68,400	5,900						74,363	0	0
Loss on redemption of preferred stock		$ 8,300						$ 8,304	$ 0	$ 0

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Share-Based Compensation (Fair Value Inputs) (Details)	12 Months Ended
	Dec. 31, 2019 Simulations $ / shares	Dec. 31, 2018 Simulations $ / shares	Dec. 31, 2017 Simulations $ / shares	Dec. 31, 2016 $ / shares
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of simulations | Simulations	100,000	100,000	100,000
Expected term (in years)	2 years 10 months 24 days	2 years 7 months 6 days	2 years 7 months 6 days
Expected volatility	47.90%	51.60%	65.30%
Risk-free interest rate	2.40%	2.60%	1.50%
Dividend yield	0.00%	0.00%	0.00%
Grant date fair value per performance-based RSU Equity Award (in dollars per share)	$ 10.78	$ 16.66	$ 16.06
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Expected term (in years)	5 years 4 months 24 days	4 years 6 months	1 year 10 months 24 days	1 year 1 month 6 days
Expected volatility	60.70%	56.90%	58.60%	68.10%
Risk-free interest rate	1.70%	1.70%	1.60%	1.50%
Dividend yield	0.00%	0.00%	0.00%	0.00%
Acquisition date fair value per Cash SAR (in dollars per share)	$ 2.11	$ 1.42	$ 0.21	$ 0.10

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Income Taxes (Schedule of Deferred Tax Assets and Liabilities) (Details) - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Deferred tax assets
Federal net operating loss carryforward	$ 110,703,000	$ 151,497,000
Interest expense carryforward	0	7,335,000
Statutory depletion carryforward	0	5,381,000
Asset retirement obligations	9,981,000	2,347,000
Derivative asset	14,823,000	0
Unvested RSU equity awards	4,928,000	2,751,000
Operating lease right-of-use assets	29,897,000	0
Other	10,445,000	991,000
Total deferred tax assets	180,777,000	170,302,000
Deferred income tax valuation allowance	0	0
Net deferred tax assets	180,777,000	170,302,000
Deferred tax liability
Oil and natural gas properties	(38,546,000)	(169,682,000)
Derivative liability	0	(10,184,000)
Operating lease liabilities	(26,511,000)	0
Total deferred tax liability	(65,057,000)	(179,866,000)
Net deferred tax asset	$ 115,720,000	0
Net deferred tax asset (liability)		$ (9,564,000)

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Leases (Lease Term and Discount Rate) (Details)	Dec. 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4 years 3 months 18 days
Financing leases	2 years 1 month 6 days
Weighted Average Discount Rate
Operating leases	5.50%
Financing leases	9.40%

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Share-Based Compensation (Cash Settled SARs) (Details) - Cash-settled SARs $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019 USD ($) $ / shares shares
Stock Appreciation Rights
Outstanding, beginning of period (n shares)	0
Granted (n shares)	0
Reissued (n shares)	3,677,955
Exercised (n shares)	0
Forfeited (n shares)	0
Expired (n shares)	0
Outstanding, end of period (n shares)	3,677,955
Vested, end of period (n shares)	3,677,955
Vested and exercisable, end of period (n shares)	0
Weighted Average Exercise Prices
Outstanding, beginning of period (in dollars per share) | $ / shares	$ 0
Granted (in dollars per share) | $ / shares	$ 0
Reissued (in dollars per share)	10.03
Exercised (in dollars per share) | $ / shares	$ 0
Forfeited (in dollars per share) | $ / shares	0
Expired (in dollars per share) | $ / shares	0
Outstanding, end of period (in dollars per share) | $ / shares	10.03
Vested, end of period (in dollars per share) | $ / shares	10.03
Vested and exercisable, end of period (in dollars per share) | $ / shares	$ 0
Weighted Average Remaining Life (In years), Outstanding, end of period	4 years 4 months 24 days
Aggregate Intrinsic Value, Outstanding, end of period | $	$ 0.0
Aggregate Intrinsic Value, Vested, end of period | $	0.0
Aggregate Intrinsic Value, Vested and exercisable, end of period | $	$ 0.0

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Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2019	Dec. 31, 2018
Stockholders’ equity:
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, shares authorized (in shares)	525,000,000	300,000,000
Common stock, shares outstanding (in shares)	396,600,022	227,582,575
Series A Preferred Stock
Stockholders’ equity:
Preferred stock, par value (in dollars per share)	$ 0.01	$ 0.01
Preferred stock, liquidation preference (in dollars per share)	$ 50.00	$ 50.00
Preferred stock, shares authorized (in shares)	2,500,000	2,500,000
Preferred stock, shares outstanding (in shares)	0	1,458,948

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Borrowings (6.375% Senior Notes) (Details) - USD ($)	Jun. 07, 2018	Dec. 31, 2019	Dec. 31, 2018
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.375%	6.375%
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument [Line Items]
Ownership percentage by parent		100.00%
Unsecured debt | 6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%	6.375%
Debt instrument aggregate principal amount	$ 400,000,000.0
Net proceeds from issuance of senior unsecured notes	$ 394,000,000.0
Unsecured debt | 6.375% Senior Notes due 2026 | Change Of Control
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.00%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal
Debt Instrument [Line Items]
Number of days to closing date of equity offerings	180 days
Debt instrument redemption price percent (as a percent)	106.375%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Maximum
Debt Instrument [Line Items]
Redemption principal amount percentage (as a percent)	35.00%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of up to 35% of the Principal | Minimum
Debt Instrument [Line Items]
Redemption principal remaining amount percentage (as a percent)	65.00%
Unsecured debt | 6.375% Senior Notes due 2026 | Prior to July 1, 2021, a Redemption of All or Part of the Principal
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2021, but Before July 1, 2022
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	103.188%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2022, but Before July 1, 2023
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	102.125%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2023, but Before July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	101.063%
Unsecured debt | 6.375% Senior Notes due 2026 | On or After July 1, 2024
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%

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Consolidated Statements of Cash Flows (Parenthetical)	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
6.125% Senior Notes due 2024
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%		6.125%	6.125%	6.125%
6.375% Senior Notes due 2026
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%	6.375%

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Property and Equipment, Net (Unevaluated Property Costs not Subject to Amortization) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Period Cost
Acquisition costs	$ 682,413,000	$ 383,238,000	$ 577,959,000	$ 115,833,000
Exploration costs	43,174,000	22,384,000	18,724,000	0
Capitalized interest	78,492,000	56,151,000	7,756,000	0
Total unevaluated properties	804,079,000	461,773,000	$ 604,439,000	$ 115,833,000
Cumulative
Acquisition costs	1,759,443,000
Exploration costs	84,282,000
Capitalized interest	142,399,000
Total unevaluated properties	$ 1,986,124,000	$ 1,404,513,000

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Acquisitions and Divestitures (Unaudited Pro Forma Financial Information) (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Carrizo
Business Acquisition [Line Items]
Revenues	$ 1,620,357	$ 1,661,171
Income (loss) from operations	614,668	767,628
Income (loss) available to common stockholders	$ 369,777	$ 734,527
Net income (loss) per common share:
Basic (in dollars per share)	$ 0.89	$ 1.87
Diluted (in dollars per share)	$ 0.89	$ 1.87
Cimarex Energy Company
Business Acquisition [Line Items]
Revenues		$ 669,236	$ 469,896
Income (loss) from operations		299,090	209,723
Income (loss) available to common stockholders		$ 324,318	$ 181,406
Net income (loss) per common share:
Basic (in dollars per share)		$ 1.49	$ 0.90
Diluted (in dollars per share)		$ 1.49	$ 0.90
Delaware Basin
Business Acquisition [Line Items]
Revenues			$ 369,527
Income (loss) from operations			144,104
Income (loss) available to common stockholders			$ 115,787
Net income (loss) per common share:
Basic (in dollars per share)			$ 0.57
Diluted (in dollars per share)			$ 0.57

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Acquisitions and Divestitures (Tables)

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Fair Value of Net Assets Acquired

The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$253,089
Unevaluated properties	287,000
Total oil and natural gas properties		$540,089
Total assets acquired		$540,089
Liabilities
Asset retirement obligations		($570	)
Total liabilities assumed		($570	)
Net Assets Acquired		$539,519

The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$137,368
Unevaluated properties	509,359
Total oil and natural gas properties		$646,727
Total assets acquired		$646,727
Liabilities
Asset retirement obligations		($168	)
Total liabilities assumed		($168	)
Net Assets Acquired		$646,559

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Consideration:
Fair value of the Company’s common stock issued		$765,373
Total consideration		$765,373
Liabilities:
Accounts payable		$37,657
Revenues and royalties payable	52,449
Operating lease liabilities - current	29,924
Fair value of derivatives - current	61,015
Other current liabilities	82,084
Long-term debt	1,984,135
Operating lease liabilities - non-current	30,070
Asset retirement obligation	26,151
Fair value of derivatives - non-current	26,960
Other long-term liabilities	17,260
Common stock warrants	10,029
Total liabilities assumed		$2,357,734
Assets:
Accounts receivable, net		$48,479
Fair value of derivatives - current	17,451
Other current assets	4,945
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	682,928
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	159,320
Operating lease right-of-use-assets	59,994
Other long term assets	2,578
Total assets acquired		$3,123,107

Unaudited Summary Pro Forma Financial Information

The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition.

	Years Ended December 31,
	2018		2017
	(In thousands)
Revenues		$669,236		$469,896
Income from operations	299,090		209,723
Net income	324,318		181,406
Basic earnings per common share	$1.49		$0.90
Diluted earnings per common share	$1.49		$0.90

The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Ameredev Acquisition.

	Year Ended December 31, 2017
	(In thousands)
Revenues		$369,527
Income from operations	144,104
Net income	115,787
Basic earnings per common share		$0.57
Diluted earnings per common share		$0.57

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.

	Years Ended December 31,
	2019		2018
	(In thousands)
Revenues		$1,620,357		$1,661,171
Income from operations	614,668		767,628
Net income	369,777		734,527
Basic earnings per common share	0.89			$1.87
Diluted earnings per common share	0.89			$1.87

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Derivative Instruments and Hedging Activities (Tables)

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Price Risk Derivatives

This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):

Year

Threshold (1)

Contingent Receipt - Annual

Threshold (1)

Contingent Receipt - Annual

Period Cash Flow Occurs

Statement of Cash Flows Presentation

Remaining Contingent Receipt - Aggregate Limit (3)

Divestiture Date Fair Value

$8,512

Pending Settlement

2019

Greater than $60/Bbl, less than $65/Bbl

$—

Equal to or greater than $65/Bbl

$—

1Q20

N/A

Remaining Potential Settlements

2020-2021

Greater than $60/Bbl, less than $65/Bbl

$9,000

Equal to or greater than $65/Bbl

$20,833

(2)

(2)

$60,000

(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.

(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

(3) The specified pricing threshold for 2019 was not met. As such, approximately $41.5 million remains for potential settlements in future years.

As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:

Contingent ExL Consideration

	Year	Threshold (1)		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Remaining Contingent Payments - Aggregate Limit				Acquisition Date Fair Value
						(In thousands)
														($69,171	)
Pending Settlement	2019		$50.00	1Q20	Investing		($50,000	)
Remaining Potential Settlements	2020-2021		$50.00	(2)	(2)		($50,000	)		($75,000	)	(3)

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities.

(3)

In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.

Schedule of Offsetting Assets

As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

໿

	As of December 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Commodity derivative instruments		$26,849			($17,511	)		$9,338
Contingent consideration arrangements	16,718			—			16,718
Fair value of derivatives - current		$43,567			($17,511	)		$26,056
Commodity derivative instruments	—			—			—
Contingent consideration arrangements	9,216			—			9,216
Fair value of derivatives - non current		$9,216			$—			$9,216
Commodity derivative instruments		($38,708	)		$17,511			($21,197	)
Contingent consideration arrangements	(50,000		)	—			(50,000		)
Fair value of derivatives - current		($88,708	)		$17,511			($71,197	)
Commodity derivative instruments	(12,935		)	—			(12,935		)
Contingent consideration arrangements	(19,760		)	—			(19,760		)
Fair value of derivatives - non current		($32,695	)		$—			($32,695	)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Fair value of derivatives - current		$78,091			($12,977	)		$65,114
Fair value of derivatives - current		($23,457	)		$12,977			($10,480	)
Fair value of derivatives - non current	(7,440		)	—			(7,440		)

Schedule of Offsetting Liabilities

As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

໿

	As of December 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Commodity derivative instruments		$26,849			($17,511	)		$9,338
Contingent consideration arrangements	16,718			—			16,718
Fair value of derivatives - current		$43,567			($17,511	)		$26,056
Commodity derivative instruments	—			—			—
Contingent consideration arrangements	9,216			—			9,216
Fair value of derivatives - non current		$9,216			$—			$9,216
Commodity derivative instruments		($38,708	)		$17,511			($21,197	)
Contingent consideration arrangements	(50,000		)	—			(50,000		)
Fair value of derivatives - current		($88,708	)		$17,511			($71,197	)
Commodity derivative instruments	(12,935		)	—			(12,935		)
Contingent consideration arrangements	(19,760		)	—			(19,760		)
Fair value of derivatives - non current		($32,695	)		$—			($32,695	)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Fair value of derivatives - current		$78,091			($12,977	)		$65,114
Fair value of derivatives - current		($23,457	)		$12,977			($10,480	)
Fair value of derivatives - non current	(7,440		)	—			(7,440		)

Schedule of Gain or Loss on Derivative Contracts

The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:

໿

	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Oil derivatives
Net gain (loss) on settlements		($11,188	)		($27,510	)		($9,067	)
Net gain (loss) on fair value adjustments	(62,125		)	72,973			(11,426		)
Total gain (loss) on oil derivatives	(73,313		)	45,463			(20,493		)
Natural gas derivatives
Net gain (loss) on settlements	7,399			238			594
Net gain (loss) on fair value adjustments	1,490			2,843			998
Total gain (loss) on natural gas derivatives	8,889			3,081			1,592
Contingent consideration arrangements
Net gain (loss) on fair value adjustments	2,315			—			—
Total gain (loss) on derivative contracts		($62,109	)		$48,544			($18,901	)

Schedule of Outstanding Oil and Natural Gas Derivative Contracts

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019:

	For the Full Year of					For the Full Year of
Oil contracts (WTI)	2020					2021
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	13,176,000					—
Weighted average price per Bbl
Ceiling (short call)		$65.28				$	—
Floor (long put)		$55.38				$	—
Floor (short put)		$45.08				$	—
Short call contracts
Total volume (Bbls)	1,674,450			(1	)	4,825,300		(1)
Weighted average price per Bbl		$75.98					$63.62
Swap contracts
Total volume (Bbls)	1,303,900					—
Weighted average price per Bbl		$55.19					$—
Swap contracts with short puts
Total volume (Bbls)	2,196,000					—
Weighted average price per Bbl
Swap		$56.06					$—
Floor (short put)		$42.50					$—
Oil contracts (Brent ICE)
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	837,500					—
Weighted average price per Bbl
Ceiling (short call)		$70.00					$—
Floor (long put)		$58.24					$—
Floor (short put)		$50.00					$—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	8,476,700					4,015,100
Weighted average price per Bbl		($1.47	)				$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,439,205					—
Weighted average price per Bbl		$2.40					$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	504,500					—
Weighted average price per Bbl		$58.22					$—
Natural gas contracts (Henry Hub)
Collar contracts (three-way collars)
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu
Ceiling (short call)		$2.75					$—
Floor (long put)		$2.50					$—
Floor (short put)		$2.00					$—
Swap contracts
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu		$2.48					$—
Short call contracts
Total volume (MMBtu)	12,078,000					7,300,000
Weighted average price per MMBtu		$3.50					$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	21,596,000					—
Weighted average price per MMBtu		($1.04	)				$—

(1)

Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.

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Leases (Tables)

12 Months Ended

Dec. 31, 2019

Leases [Abstract]

Lease, Cost

The table below presents the components of the Company’s lease costs for the year ended December 31, 2019.

	Year Ended December 31, 2019
	(In thousands)
Components of Lease Costs
Finance lease costs		$92
Amortization of right-of-use assets (1)	82
Interest on lease liabilities (2)	10
Operating lease cost (3)	38,076
Impairment of Operating lease ROU assets (4)	16,209
Short-term lease cost (5)	3,640
Variable lease costs (6)	—
Total lease costs		$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 year ended December 31, 2019, approximately $34.9 million are costs associated with drilling rigs and are capitalized to “Evaluated properties, net” in the consolidated balance sheets and the other remaining operating lease costs are components of “General and administrative” and “Lease operating” in the consolidated statements of operations.

(4) In conjunction with the Carrizo Acquisition, the Company evaluated certain of its office leases for impairment as the determination was made in 2019 that certain corporate offices would be consolidated. Upon evaluation, the Company recorded an impairment of certain of its Operating lease ROU assets of $16.2 million which is 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.

Assets And Liabilities, Lessee

The table below presents supplemental balance sheet information for the Company’s leases as of December 31, 2019.

	Year Ended December 31, 2019
	(In thousands)
Leases
Operating leases:
Operating lease ROU assets		$63,908
Current operating lease liabilities		$42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Financing leases:
Other property and equipment		$2,197
Accumulated depreciation	(82		)
Other property and equipment, net	2,115
Current financing lease liabilities		$1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	2,141

Non-Cash Investing and Supplemental Cash Flow Information

The table below presents the weighted average remaining lease terms and weighted average discounts rates for the Company’s leases as of December 31, 2019.

	December 31, 2019
Weighted Average Remaining Lease Terms (In years)
Operating leases	4.3
Financing leases	2.1
Weighted Average Discount Rate
Operating leases	5.5	%
Financing leases	9.4	%

Lessee, Operating Lease, Liability, Maturity

The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019.

	Operating Leases		Financing Leases
	(In thousands)
2020		$45,864		$1,475
2021	11,648		275
2022	4,363		234
2023	4,209		233
2024	4,110		38
Thereafter	17,902		—
Total lease payments	88,096		2,255
Less imputed interest	8,150		114
Total lease liabilities		$79,946		$2,141

Finance Lease, Liability, Maturity

The table below presents the maturity of the Company’s lease liabilities as of December 31, 2019.

	Operating Leases		Financing Leases
	(In thousands)
2020		$45,864		$1,475
2021	11,648		275
2022	4,363		234
2023	4,209		233
2024	4,110		38
Thereafter	17,902		—
Total lease payments	88,096		2,255
Less imputed interest	8,150		114
Total lease liabilities		$79,946		$2,141

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Share-Based Compensation

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Share-Based Compensation

Share-Based Compensation

2018 Omnibus Incentive Plan

The 2018 Omnibus Incentive Plan, which became effective May 10, 2018 following shareholder approval (the “2018 Plan”), authorized and reserved for issuance 9,400,000 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 2018 Plan replaced the 2011 Omnibus Incentive Plan (the “Prior Plan”), and included a provision at inception whereby all remaining, un-issued and authorized shares from the Prior Plan became issuable under the 2018 Plan. This transfer provision resulted in the transfer of an additional 1,322,742 shares into the 2018 Plan, increasing the quantity authorized and reserved for issuance under the 2018 Plan to 10,722,742 at the inception of the 2018 Plan. Another provision provided that shares, which would otherwise become available for issuance under the Prior Plan as a result of vesting and/or forfeiture of any equity awards existing as of the effective date of the 2018 Plan, would also increase the authorized shares available to the 2018 Plan. As a result of the Merger, the 2018 Plan was amended and restated to incorporate the 2017 Incentive Plan of Carrizo Oil & Gas, Inc. (the “Carrizo Plan”), including outstanding awards under the Carrizo Plan and shares available to grant to the former employees of Carrizo which were converted to shares of the Company by applying the conversion ratio of 1.75 shares of the Company per one share of Carrizo (the “Amended and Restated 2018 Plan”). At December 31, 2019, there were 13,814,216 shares available for future share-based awards under the Amended and Restated 2018 Plan. 

RSU Equity Awards

The following table summarizes RSU Equity Award activity for the years ended December 31, 2019, 2018 and 2017:

	RSU Equity Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	1,448			$10.81
Granted (1) (2)	1,173			$12.25
Vested (3)	(797	)		$11.35
Forfeited	(34	)		$9.57
Unvested at the end of the period	1,790			$11.54
For the Year Ended December 31, 2018
Unvested at the beginning of the period	1,790			$11.54
Granted (1)	872			$13.89
Vested (3)	(506	)		$9.56
Forfeited	(53	)		$11.43
Unvested at the end of the period	2,103			$13.24
For the Year Ended December 31, 2019
Unvested at the beginning of the period	2,103			$13.24
Granted (1)	1,881			$8.60
Vested (3)	(1,062	)		$12.35
Forfeited	(227	)		$10.59
Unvested at the end of the period	2,695			$10.57

(1) Includes 399,425, 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0% - 200% for the years ended December 31, 2019, 2018 and 2017, respectively.

(2) Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142% of target at issuance in 2017.

(3) The fair value of shares vested was $7.3 million, $6.3 million and $9.0 million during the years ended December 31, 2019, 2018 and 2017, respectively.

Performance-based RSU Equity Awards that vest are 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% of the base units awarded. 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	2019		2018		2017
Vesting Multiplier	100	%	142	%	142% - 200%
Target	88,790		83,002		258,406
Vested at end of performance period	88,790		117,862		441,232
Did not vest at end of performance period	—		—		—

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, 2019, 2018 and 2017, the grant date fair value of the performance-based RSU Equity Awards, calculated using a Monte Carlo simulation, was $4.3 million, $3.5 million, and $2.6 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, 2019, 2018 and 2017:

	Years Ended December 31,
Performance-based Awards	2019		2018		2017
Number of simulations	100,000		100,000		100,000
Expected term (in years)	2.9		2.6		2.6
Expected volatility	47.9	%	51.6	%	65.3	%
Risk-free interest rate	2.4	%	2.6	%	1.5	%
Dividend yield	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$10.78		$16.66		$16.06

As of December 31, 2019, unrecognized compensation costs related to unvested RSU Equity Awards were $15.1 million and will be recognized over a weighted average period of 1.3 years.

Cash-Settled RSU Awards

The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2019, 2018 and 2017:

	Cash-Settled RSU Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	734			$8.87
Granted	283			$12.13
Vested	(379	)		$9.61
Forfeited	(13	)		$9.54
Unvested at the end of the period	625			$9.88
For the Year Ended December 31, 2018
Unvested at the beginning of the period	625			$9.88
Granted	348			$14.16
Vested	(276	)		$9.04
Forfeited	(19	)		$12.05
Unvested at the end of the period	678			$12.36
For the Year Ended December 31, 2019
Unvested at the beginning of the period	678			$12.36
Granted	424			$8.14
Vested	(164	)		$12.02
Forfeited	(83	)		$11.58
Unvested at the end of the period	855			$10.41

All of the Company’s outstanding Cash-Settled RSU Awards include a performance-based vesting condition that determines the actual number of units that will ultimately vest. The number of Cash-Settled RSU Awards 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% of the base units awarded.

For the year ended December 31, 2019, 147,492 performance-based Cash-Settled RSU Awards vested at 100% of their issued units, resulting in a payable amount of $0.7 million in 2020. Also during 2019, 16,600 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $0.1 million in 2019.

For the year ended December 31, 2018, 207,261 performance-based Cash-Settled RSU Awards subject to the peer performance-based vesting described above, vested between 100% to 163% of their issued units, depending on the date of the vesting, resulting in cash payments of $0.1 million in 2018 and $1.3 million in 2019. Also during 2018, 129,753 non-performance-based Cash-Settled RSU Awards vested, resulting in cash payments of $1.8 million during 2018.

The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:

	December 31,
	2019		2018
Other current liabilities		$966		$1,390
Other long-term liabilities	2,089		2,067
Total Cash-Settled RSU Awards		$3,055		$3,457

As of December 31, 2019, the Company had the following performance-based Cash-Settled RSU Awards outstanding:

	Target Awards Outstanding	Potential Minimum Units Vesting	Potential Maximum Units Vesting
	(In thousands)
Vesting in 2020	292	—	586
Vesting in 2021	373	—	745
Vesting in 2022	—	—	—
Other	24	24	24
Total Cash-Settled RSU Awards	689	24	1,355

As of December 31, 2019, unrecognized compensation costs related to unvested Cash-Settled RSU Awards were $1.1 million and will be recognized over a weighted average period of 1.5 years.

Cash-Settled SARs

As a result of the Merger, Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The table below summarizes the Cash SAR activity for the year ended December 31, 2019.

	Stock Appreciation Rights	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)
For the Year Ended December 31, 2019
Outstanding, beginning of period	—		$—
Granted	—		$—
Reissued	3,677,955		$10.03
Exercised	—		$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	3,677,955		$10.03	4.4		$—
Vested, end of period	3,677,955		$10.03	0		$—
Vested and exercisable, end of period	—		$—	0		$—

The acquisition date fair value of the Cash SARs, calculated using the Black-Scholes-Merton option pricing model was $4.6 million. The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below:

	2019		2018		2017		2016
Fair Value Inputs
Expected term (in years)	5.4		4.5		1.9		1.1
Expected volatility	60.7	%	56.9	%	58.6	%	68.1	%
Risk-free interest rate	1.7	%	1.7	%	1.6	%	1.5	%
Dividend yield	—	%	—	%	—	%	—	%
Acquisition date fair value per Cash SAR	$2.11		$1.42		$0.21		$0.10
Expiration date	March 17, 2026		March 17, 2025		March 23, 2022		March 17, 2021

The liability for Cash SARs as of December 31, 2019 was $5.0 million, all of which was classified as “Other current liabilities” in the consolidated balance sheets in the respective period. Changes to the fair value of the Cash SARs are included in “General and

administrative” in the consolidated statements of operations. As all Cash SARs are vested, there is no unrecognized compensation costs as of December 31, 2019.

Share-Based Compensation Expense, Net

The following table presents share-based compensation expense for each respective period:

	Years Ended December 31,
	2019				2018				2017
Share-based compensation cost for:	Equity		Liability		Equity		Liability		Equity		Liability
RSU Equity Awards (1)		$14,322		$—		$9,460		$—		$10,225		$—
Cash-Settled RSU Awards (1)	—		1,021		—		336		—		4,294
Cash SARs	—		443		—		—		—		—
Total share-based compensation cost (2)		$14,322		$1,464		$9,460		$336		$10,225		$4,294

(1) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017.

(2)

The portion of this share-based compensation cost that was included in “General and administrative” totaled $11.1 million, $6.4 million and $5.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, and the portion capitalized to oil and gas properties was $4.7 million, $3.4 million and $3.2 million for the years ended December 31, 2019, 2018, and 2017, respectively.

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Earnings Per Share

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings (loss) per share is computed by dividing income available to common stockholders by the weighted average number of shares outstanding for the periods presented. The calculation of diluted earnings per share includes the potential dilutive impact of non-vested restricted shares outstanding during the periods presented, as calculated using the treasury stock method, unless their effect is anti-dilutive. The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended December 31,
	2019			2018			2017
	(In thousands, except per share amounts)
Net income		$67,928			$300,360			$120,424
Preferred stock dividends	(3,997		)	(7,295		)	(7,295		)
Loss on redemption of preferred stock	(8,304		)	—			—
Income available to common stockholders		$55,627			$293,065			$113,129
Basic weighted average common shares outstanding	233,140			216,941			201,526
Dilutive impact of restricted stock	410			655			576
Diluted weighted average common shares outstanding	233,550			217,596			202,102
Income Available to Common Stockholders Per Common Share
Basic		$0.24			$1.35			$0.56
Diluted		$0.24			$1.35			$0.56
Restricted stock (1)	998			89			16

(1)

Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

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Summary of Significant Accounting Policies (Tables)

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Schedule of Major Customers

The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented:

	Years Ended December 31,
	2019	2018	2017
Rio Energy International, Inc.	26%	28%	17%
Enterprise Crude Oil, LLC	19%	14%	18%
Plains Marketing, L.P.	15%	21%	29%
Shell Trading Company	10%	*	*

* - Less than 10% for the applicable year.

Non-Cash Investing and Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Interest paid, net of capitalized amounts		$—			$—			$—
Income taxes paid (1)	—			—			—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$3,414			$—			$—
Investing cash flows from operating leases	32,529			—			—
Non-cash investing and financing activities:
Change in accrued capital expenditures		($31,475	)		($52,757	)		($39,532	)
Change in asset retirement costs	13,559			8,730			(607		)
Contingent consideration arrangement	8,512			—			—
ROU assets obtained in exchange for lease liabilities:
Operating leases		$66,914			$—			$—
Financing leases	2,197			—			—

(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2019.

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Subsequent Eventss (Unaudited)

12 Months Ended

Dec. 31, 2019

Subsequent Events [Abstract]

Subsequent Events (Unaudited)

Subsequent Events (Unaudited)

Contingent Consideration Arrangements

For the year ended December 31, 2019, the specified pricing thresholds related certain of the contingent consideration arrangements acquired in the Carrizo Acquisition were exceeded. As a result, in January 2020, the Company paid $50.0 million and received $10.0 million from settlement of a portion of these contingent consideration arrangements.

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Asset Retirement Obligations

12 Months Ended

Dec. 31, 2019

Asset Retirement Obligation [Abstract]

Asset Retirement Obligations

Asset Retirement Obligations

The table below summarizes the activity for the Company’s asset retirement obligations:

	Years Ended December 31,
	2019			2018
	(In thousands)
Asset retirement obligations, beginning of period		$14,292			$6,020
Accretion expense	945			874
Liabilities incurred	615			973
Increase due to acquisition of oil and gas properties	26,107			570
Liabilities settled	(3,394		)	(1,288		)
Dispositions	(1,776		)	(614		)
Revisions to estimates	12,944			7,757
Asset retirement obligations, end of period	49,733			14,292
Less: Current asset retirement obligations	(873		)	(3,887		)
Non-current asset retirement obligations		$48,860			$10,405

Certain of the Company’s operating agreements require that assets be restricted for future abandonment obligations. Amounts recorded on the consolidated balance sheets at December 31, 2019 and 2018 as long-term restricted investments were $3.5 million and $3.4 million, respectively, and 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.

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Fair Value Measurements (Summary of Financial Instruments at Carrying and Fair Value) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 20, 2019	Dec. 31, 2018	Jun. 07, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%					6.25%
6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%				6.125%	6.125%	6.125%
8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	8.25%	8.25%
6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%		6.375%
Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.375%			6.375%
Principal Amount
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	$ 1,900,000		$ 1,000,000
Principal Amount | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	650,000		0
Principal Amount | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	600,000		600,000
Principal Amount | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	250,000		0
Principal Amount | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	400,000		400,000
Fair Value
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Total	1,930,929		930,000
Fair Value | Unsecured debt | 6.25% Senior Notes due 2023
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	658,125		0
Fair Value | Unsecured debt | 6.125% Senior Notes due 2024
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	611,130		558,000
Fair Value | Unsecured debt | 8.25% Senior Notes due 2025
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	256,250		0
Fair Value | Unsecured debt | 6.375% Senior Notes due 2026
Fair Value, Balance Sheet Grouping, Financial Statement Captions [Line Items]
Senior Notes	$ 405,424		$ 372,000

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Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Costs Incurred) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Acquisition costs:
Evaluated properties	$ 49,572	$ 347,305	$ 156,340
Unevaluated properties	107,347	466,816	499,295
Development costs	189,259	259,410	148,254
Exploration costs	309,013	323,458	239,453
Total costs incurred	$ 655,191	$ 1,396,989	$ 1,043,342

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Subsequent Eventss (Unaudited) (Details) - Subsequent Event $ in Millions	1 Months Ended
	Jan. 31, 2020 USD ($)
Subsequent Event [Line Items]
Payments of contingent consideration	$ 50.0
Proceeds from settlement of contingent consideration arrangements	$ 10.0

XML

Derivative Instruments and Hedging Activities (Narrative) (Details) - Acquired Contingent Consideration	Jan. 31, 2020 USD ($)	Dec. 31, 2019 $ / bbl $ / MMBTU
Subsequent Event
Derivative [Line Items]
Aggregate settlements limit | $	$ 13,000,000.0
Contingent payment received | $	$ 10,000,000.0
Minimum
Derivative [Line Items]
Threshold | $ / bbl		53.00
Weighted average price (in dollars per share) | $ / MMBTU		3.18
Maximum
Derivative [Line Items]
Threshold | $ / bbl		60.00
Weighted average price (in dollars per share) | $ / MMBTU		3.30

XML

Accounts Receivable, Net (Tables)

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable [Table Text Block]

	As of December 31,
	2019			2018
	(In thousands)
Oil and natural gas receivables		$165,275			$87,062
Joint interest receivables	42,493			42,373
Other receivables	3,231			3,150
Total	210,999			132,585
Allowance for doubtful accounts	(1,536		)	(865		)
Total accounts receivable, net		$209,463			$131,720

XML

Supplemental Quarterly Financial Information (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Schedule of Quarterly Financial Information

2019	First Quarter (2)			Second Quarter (3)		Third Quarter (4)		Fourth Quarter (5)
	(In thousands, except per share amounts)
Total operating revenues		$153,047			$167,052		$155,378		$196,095
Income from operations	43,225			58,509		52,544		18,380
Net income (loss)	(19,543		)	55,180		55,834		(23,543		)
Income (loss) available to common stockholders	(21,367		)	53,357		47,180		(23,543		)
Income (loss) available to common stockholders per common share (1)
Basic		($0.09	)		$0.23		$0.21		($0.09	)
Diluted		($0.09	)		$0.23		$0.21		($0.09	)

2018	First Quarter		Second Quarter (6)		Third Quarter (7)		Fourth Quarter (8)
	(In thousands, except per share amounts)
Total operating revenues		$127,440		$137,075		$161,214		$161,895
Income from operations	60,986		67,400		72,811		58,333
Net income	55,761		50,474		37,931		156,194
Income available to common stockholders	53,937		48,650		36,108		154,370
Income available to common stockholders per common share (1)
Basic		$0.27		$0.23		$0.16		$0.68
Diluted		$0.27		$0.23		$0.16		$0.68

(1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(2) First quarter of 2019 included the following:

a. $67.3 million loss on derivative contracts

(3) Second quarter of 2019 included the following:

a. $14.0 million gain on derivative contracts

(4) Third quarter of 2019 included the following:

a. $21.8 million gain on derivative contracts

b. $5.9 million of merger and integration costs associated with the merger with Carrizo

c. $8.3 million loss on redemption of Preferred Stock

(5) Fourth quarter of 2019 included the following:

a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

b. $68.4 million of merger and integration costs associated with the merger with Carrizo

c. $30.7 million loss on derivative contracts

d. $4.9 million loss on extinguishment of debt

(6) Second quarter of 2018 included the following:

a. $16.6 million loss on derivative contracts

(7) Third quarter of 2018 included the following:

a. $34.3 million loss on derivative contracts

(8) Fourth quarter of 2018 included the following:

a. 103.9 million gain on derivative contracts

XML

Revenue Recognition (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Lease operating	$ 91,827	$ 69,180	$ 49,907
Performance obligation, description of timing	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.
Accounts Receivable
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Customer assets	$ 165,300	87,100
Natural Gas, Gathering and Treating Fees
Revenue, Initial Application Period Cumulative Effect Transition [Line Items]
Gathering and treating fees recorded as a reduction to natural gas revenues	$ 10,500	$ 7,600
Lease operating			$ 3,400

XML

Cover Page - USD ($)
$ in Billions

12 Months Ended

Dec. 31, 2019

Feb. 21, 2020

Jun. 30, 2019

Cover page.

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2019

Document Transition Report

false

Entity File Number

001-14039

Entity Registrant Name

Callon Petroleum Co

Entity Incorporation, State or Country Code

DE

Entity Tax Identification Number

64-0844345

Entity Address, Address Line One

One Briarlake Plaza

Entity Address, Address Line Two

2000 W. Sam Houston Parkway S., Suite 2000

Entity Address, City or Town

Houston,

Entity Address, State or Province

TX

Entity Address, Postal Zip Code

77042

City Area Code

281

Local Phone Number

589-5200

Title of 12(b) Security

Common Stock, $0.01 par value

Trading Symbol

CPE

Security Exchange Name

NYSE

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

Entity Shell Company

false

Entity Public Float

$ 1.5

Entity Common Stock, Shares Outstanding

396,684,449

Documents Incorporated by Reference

Portions of the definitive Proxy Statement of Callon Petroleum Company (to be filed no later than 120 days after December 31, 2019) relating to the Annual Meeting of Stockholders to be held on May 14, 2020, which are incorporated into Part III of this Form 10-K.

Entity Central Index Key

0000928022

Current Fiscal Year End Date

--12-31

Document Fiscal Year Focus

2019

Document Fiscal Period Focus

FY

Amendment Flag

false

XML

Consolidated Statements of Stockholders' Equity - USD ($) shares in Thousands, $ in Thousands	Total	Preferred Stock	Common Stock	Capital in Excess of Par	Retained Earnings (Accumulated Deficit)
Beginning balance (in shares) at Dec. 31, 2016		1,459	201,041
Beginning balance at Dec. 31, 2016	$ 1,733,402	$ 15	$ 2,010	$ 2,171,514	$ (440,137)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	120,424				120,424
Shares issued pursuant to employee benefit plans	311			311
Restricted stock (in shares)			769
Restricted stock	9,106		$ 8	9,098
Common stock issued for Carrizo Acquisition	18			18
Impact of forfeiture estimate	0			(418)	(418)
Preferred stock dividend	(7,295)				(7,295)
Loss on redemption of preferred stock	0
Ending balance (in shares) at Dec. 31, 2017		1,459	201,836
Ending balance at Dec. 31, 2017	1,855,966	$ 15	$ 2,018	2,181,359	(327,426)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	300,360				300,360
Shares issued pursuant to employee benefit plans (in shares)			45
Shares issued pursuant to employee benefit plans	533			533
Restricted stock (in shares)			402
Restricted stock	7,656		$ 5	7,651
Common stock issued (in shares)			25,300
Common stock issued for Carrizo Acquisition	287,988		$ 253	287,735
Preferred stock dividend	(7,295)				(7,295)
Loss on redemption of preferred stock	0
Ending balance (in shares) at Dec. 31, 2018		1,459	227,583
Ending balance at Dec. 31, 2018	2,445,208	$ 15	$ 2,276	2,477,278	(34,361)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income	67,928				67,928
Shares issued pursuant to employee benefit plans (in shares)			24
Shares issued pursuant to employee benefit plans	154			154
Restricted stock (in shares)			779
Restricted stock	11,630		$ 8	11,622
Common stock issued for Carrizo Acquisition (in shares)			168,214
Common stock issued for Carrizo Acquisition	765,373		$ 1,682	763,691
Common stock warrants reissued for Carrizo Acquisition	10,029			10,029
Preferred stock dividend	(3,997)				(3,997)
Preferred stock redemption (in shares)		(1,459)
Preferred stock redemption	(64,713)	$ (15)		(64,698)
Loss on redemption of preferred stock	(8,304)				(8,304)
Ending balance (in shares) at Dec. 31, 2019		0	396,600
Ending balance at Dec. 31, 2019	$ 3,223,308	$ 0	$ 3,966	$ 3,198,076	$ 21,266

XML

Borrowings (Schedule of Borrowings) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 20, 2019	Dec. 31, 2018	Dec. 31, 2017	May 19, 2017	Oct. 03, 2016
Principal components:
Total principal outstanding	$ 3,185,000		$ 1,200,000
Unamortized deferred financing costs for Senior Notes	(14,359)		(16,996)
Total carrying value of borrowings	3,186,109		1,189,473
Deferred financing costs	22,233		6,087
New Credit Facility
Principal components:
Total principal outstanding	1,285,000
6.25% Senior Notes due 2023
Principal components:
Total principal outstanding	650,000		0
Unamortized premium for 6.125% Senior Notes	$ 4,838		0
Debt instrument, interest rate, stated (as a percent)	6.25%	6.25%				6.25%
6.125% Senior Notes due 2024
Principal components:
Total principal outstanding	$ 600,000		600,000
Unamortized premium for 6.125% Senior Notes	$ 5,344		6,469
Debt instrument, interest rate, stated (as a percent)	6.125%			6.125%	6.125%	6.125%
8.25% Senior Notes due 2025
Principal components:
Total principal outstanding	$ 250,000		0
Unamortized premium for 6.125% Senior Notes	$ 5,286		0
Debt instrument, interest rate, stated (as a percent)	8.25%	8.25%
6.375% Senior Notes due 2026
Principal components:
Total principal outstanding	$ 400,000		$ 400,000
Debt instrument, interest rate, stated (as a percent)	6.375%		6.375%
Secured Debt | Senior Secured Revolving Credit Facility due 2024
Principal components:
Total principal outstanding			$ 200,000

XML

Summary of Significant Accounting Policies

12 Months Ended

Dec. 31, 2019

Accounting Policies [Abstract]

Summary of Significant Accounting Policies

Summary of Significant Accounting Policies

Basis of Presentation and Principles of Consolidation

The consolidated financial statements include the accounts of the Company after elimination of intercompany transactions and balances and are presented in accordance with U.S. generally accepted accounting principles (“GAAP”). The Company proportionately consolidates its undivided interests in oil and gas properties as well as investments in unincorporated entities, such as partnerships and limited liability companies where the Company, as a partner or member, has undivided interests in the oil and gas properties. In the opinion of management, the accompanying audited consolidated financial statements reflect all adjustments, including normal recurring adjustments and all intercompany account balance and transaction eliminations, necessary to present fairly the Company’s financial position, results of its operations and cash flows for the periods indicated. Certain prior year amounts have been reclassified to conform to current year presentation.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make judgments affecting estimates and assumptions for reported amounts of assets and liabilities, disclosure of contingent assets and liabilities at the date of the financial statements, and the reported amounts of revenues and expenses during the reporting period. Estimates of proved oil and gas reserves are used in calculating depreciation, depletion and amortization (“DD&A”) of proved 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, grant date fair value of stock-based awards, and contingency, litigation, and environmental liabilities. Actual results could differ from those estimates.

Cash and Cash Equivalents

The Company considers all highly liquid investments with original maturities of three months or less to be cash equivalents.

Accounts Receivable, Net

Accounts receivable, net consists primarily of receivables from oil, natural gas, and NGL purchasers and joint interest owners in properties the Company operates. The Company generally has the right to withhold future revenue distributions to recover past due receivables from joint interest owners. Generally, the Company’s oil, natural gas, and NGL receivables are collected within 30 to 90 days. The Company’s allowance for doubtful accounts and bad debt expense was immaterial for all period presented.

Concentration of Credit Risk and Major Customers

The concentration of accounts receivable from entities in the oil and gas industry may impact the Company’s overall credit risk such that these entities may be similarly affected by changes in economic and other industry conditions. The Company does not believe the loss of any one of its purchasers would materially affect its ability to sell the oil and gas it produces as other purchasers are available in its primary areas of activity. The Company had the following major customers that represented 10% or more of its total revenues for at least one of the periods presented:

	Years Ended December 31,
	2019	2018	2017
Rio Energy International, Inc.	26%	28%	17%
Enterprise Crude Oil, LLC	19%	14%	18%
Plains Marketing, L.P.	15%	21%	29%
Shell Trading Company	10%	*	*

* - Less than 10% for the applicable year.

The Company’s counterparties to its commodity derivative instruments include lenders under the Company’s credit agreement (“Lender Counterparty”) as well as counterparties who are not lenders under the Company’s credit agreement (“Non-Lender Counterparty”). As each Lender Counterparty has an investment grade credit rating and the Company has obtained a guaranty from each Non-Lender Counterparty’s parent company which has an investment grade credit rating, the Company believes it does not have significant credit risk with its commodity derivative instrument counterparties. Although the Company does not currently anticipate nonperformance from its counterparties, it continually monitors the credit ratings of each Lender Counterparty and each Non-Lender Counterparty’s parent company. The Company executes its derivative instruments with multiple counterparties to minimize its credit exposure to any individual counterparty.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting under which all productive and nonproductive costs directly associated with property acquisition, exploration, and development activities are capitalized as oil and gas properties. Internal costs that are directly related to acquisition, exploration, and development activities, including salaries, benefits, and stock-based compensation, are capitalized to either evaluated or unevaluated oil and gas properties based on the type of activity. Internal costs related to production and similar activities are expensed as incurred. 

Proceeds from the sale or disposition of evaluated and unevaluated oil and natural gas properties are accounted for as a reduction of evaluated oil and gas property costs unless the sale significantly alters the relationship between capitalized costs and proved reserves, in which case a gain or loss is recognized. For the years ended December 31, 2019, 2018 and 2017, the Company did not have any sales of oil and gas properties that significantly altered such relationship.

Capitalized oil and gas property costs are amortized on an equivalent unit-of-production method, converting natural gas to barrels of oil equivalent at the ratio of six thousand cubic feet of gas to one barrel of oil, which represents their approximate relative energy content. The equivalent unit-of-production depletion rate is computed on a quarterly basis by dividing current quarter production by proved oil and gas reserves at the beginning of the quarter then applying such amortization rate to evaluated oil and gas property costs, which includes estimated asset retirement costs, less accumulated amortization, plus estimated future expenditures to be incurred in developing proved reserves, net of estimated salvage values.

Excluded from this amortization are costs associated with unevaluated leasehold and seismic costs associated with specific unevaluated properties and related capitalized interest. Unevaluated property costs are transferred to evaluated property costs at such time as wells are completed on 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 unproved properties and the weighted average interest rate of outstanding borrowings. Capitalized interest cannot exceed gross interest expense.

Under full cost accounting rules, the Company reviews the net book value of its oil and gas properties each quarter. Under these rules, the net book value of oil and gas properties, less related deferred income taxes, are limited to the “cost center ceiling” equal to (i) the sum of (a) the present value of estimated future net revenues from proved oil and gas reserves, less estimated future expenditures to be incurred in developing and producing the proved reserves computed using a discount factor of 10%, (b) the costs of unevaluated properties not being amortized, and (c) the lower of cost or estimated fair value of unevaluated properties included in the costs being amortized; less (ii) related income tax effects. Any excess of the net book value of oil and gas properties, less related deferred income taxes, over the cost center ceiling is recognized as a write-down of evaluated oil and gas properties. A write-down recognized in one period may not be reversed in a subsequent period even if higher commodity prices in the future result in a cost center ceiling in excess of the net book value of oil and gas properties, less related deferred income taxes.

The estimated future net revenues used in the cost center ceiling are calculated using the average realized prices for sales of oil, NGLs, and natural gas on the first calendar day of each month during the 12-month period prior to the end of the current quarter (“12-Month Average Realized Price”), held flat for the life of the production, except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts. Prices do not include the impact of commodity derivative instruments as the Company elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. The Company did not recognize a write-down of evaluated oil and natural gas properties for the years ended December 31, 2019, 2018, and 2017. 

Other Property and Equipment

The Company depreciates its other property and equipment using the straight-line method based on estimated useful lives of three to twenty years. Depreciation expense of $0.7 million, $1.1 million and $0.9 million relating to other property and equipment was included in “General and administrative expense” in the consolidated statements of operations for the years ended December 31, 2019, 2018 and 2017, respectively. The Company reviews its other property and equipment for impairment when indicators of impairment exist.

Deferred Financing Costs

Deferred financing costs associated with the Company’s senior notes are classified as a reduction of the related senior notes carrying value on the consolidated balance sheets and are amortized to interest expense using the straight-line method over the terms of the related senior notes. Deferred financing costs associated with the revolving credit facility are classified in “Other long-term assets” in the consolidated balance sheets and are amortized to interest expense using the straight-line method over the term of the facility. Amortization of deferred financing costs, net of amortization of premiums, of $2.9 million, $2.5 million and $2.2 million were recorded for the years ended December 31, 2019, 2018 and 2017, respectively. 

Asset Retirement Obligations

The Company records an estimate of the fair value of liabilities for obligations associated with plugging and abandoning oil and gas wells, removing production equipment and facilities and restoring the surface of the land in accordance with the terms of oil and gas leases and applicable local, state and federal laws. Estimates involved in determining asset retirement obligations include the future plugging and abandonment costs of wells and related facilities, the ultimate productive life of the properties, a credit-adjusted risk-free discount rate and an inflation factor in order to determine the present value of the asset retirement obligation. The present value of the asset retirement obligations is accreted each period and the increase to the obligation is reported in “Depreciation, depletion and amortization” in the consolidated statements of operations. To the extent future revisions to these assumptions impact the present value of the existing asset retirement obligation liability, a corresponding adjustment is made to evaluated properties in the consolidated balance sheets. See “Note 14 - Asset Retirement Obligations” for additional information.

Derivative Instruments

The Company uses commodity derivative instruments to mitigate the effects of commodity price volatility for a portion of its forecasted sales of production and achieve a more predictable level of cash flow. All commodity derivative instruments are recorded in the consolidated balance sheets as either an asset or liability measured at fair value. The Company nets its commodity derivative instrument fair value amounts executed with the same counterparty to a single asset or liability pursuant to International Swap Dealers Association Master Agreements (“ISDAs”), which provide for net settlement over the term of the contract and in the event of default or termination of the contract. The Company does not enter into commodity derivative instruments for speculative purposes.

The Company is also party to contingent consideration arrangements that include obligations to pay or rights to receive additional consideration if commodity prices exceed specified thresholds during certain periods in the future. These contingent consideration assets and liabilities are required to be bifurcated and accounted for separately as derivative instruments as they are not considered to be clearly and closely related to the host contract, and recognized at their acquisition or divestiture date fair value in the consolidated balance sheets.

The Company has elected not to meet the criteria to qualify its commodity derivative instruments for hedge accounting treatment. As such, all gains and losses as a result of changes in the fair value of commodity derivative instruments, as well as its contingent consideration arrangements, are recognized as “(Gain) loss on derivative contracts” in the consolidated statements of operations in the period in which

the changes occur. See “Note 8 - Derivative Instruments and Hedging Activities” and “Note 9 - Fair Value Measurements” for further discussion.

Revenue Recognition

The Company recognizes revenues from the sales of oil and natural gas to its customers and presents them disaggregated on the Company’s consolidated statements of operations. Revenue is recognized at the point in time when control of the product transfers to the customer. Revenue accruals are recorded monthly and are based on estimated production delivered to a purchaser and the expected price to be received. Variances between estimates and the actual amounts received are recorded in the month payment is received. See “Note 3 - Revenue Recognition” for further discussion.

Income Taxes

Income taxes are recognized based on earnings reported for tax return purposes in addition to a provision for deferred income taxes. Deferred income taxes are recognized at the end of each reporting period for the future tax consequences of cumulative temporary differences between the tax basis of assets and liabilities and their reported amounts in the Company’s consolidated financial statements based on existing tax laws and enacted statutory tax rates applicable to the periods in which the temporary differences are expected to affect taxable income. GAAP requires the recognition of a deferred tax asset for net operating loss carryforwards and tax credit carryforwards. The Company assesses the realizability of its deferred tax assets on a quarterly basis by considering all available evidence (both positive and negative) to determine whether it is more likely than not that all or a portion of the deferred tax assets will not be realized and a valuation allowance is required. As of December 31, 2019 and 2018, the Company did not have a valuation allowance against its deferred tax assets. See “Note 12 - Income Taxes” for further discussion.

Share-Based Compensation

The Company grants restricted stock unit awards that may be settled in common stock (“RSU Equity Awards”) or cash (“Cash-Settled RSU Awards”), some of which are subject to achievement of certain performance conditions. In addition, as a result of the Merger, all stock appreciation rights to be settled in cash (“Cash SARs”) previously granted by Carrizo that were outstanding as of closing were canceled and converted into a vested Cash SAR covering shares of the Company’s common stock. Share-based compensation expense is recognized as “General and administrative expense” in the consolidated statements of operations. The Company accounts for forfeitures of equity-based incentive awards as they occur. See “Note 10 - Share-Based Compensation” for further details of the awards discussed below.

RSU Equity Awards and Cash-Settled RSU Awards. Share-based compensation expense for RSU Equity Awards is based on the grant-date fair value and recognized over the vesting period (generally three years for employees and one year for non-employee directors) using the straight-line method. For RSU Equity Awards with vesting terms subject to a performance condition, share-based compensation expense is based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model with the estimated value recognized over the vesting period (generally three years). Cash-Settled RSU Awards subject to a performance condition that the Company expects or is required to settle in cash, are accounted for as liabilities with share-based compensation expense based on the fair value measured at each reporting period as calculated using a Monte Carlo pricing model, with the estimated fair value recognized over the vesting period (generally three years). 

Cash SARs. Cash SARs previously granted by Carrizo that were outstanding at closing of the Merger were canceled and converted into a Cash SAR covering shares of the Company’s common stock, with the conversion calculated as prescribed in the agreement governing the Merger. The Cash SARs were recorded at their acquisition date fair value, which was determined using a Black-Scholes-Merton option pricing model, with the fair value liability subsequently remeasured at the end of each reporting period. 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 will expire between one and seven years, depending on the date of grant.

Supplemental Cash Flow Information

The following table sets forth supplemental cash flow information for the periods indicated:

	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Interest paid, net of capitalized amounts		$—			$—			$—
Income taxes paid (1)	—			—			—
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases		$3,414			$—			$—
Investing cash flows from operating leases	32,529			—			—
Non-cash investing and financing activities:
Change in accrued capital expenditures		($31,475	)		($52,757	)		($39,532	)
Change in asset retirement costs	13,559			8,730			(607		)
Contingent consideration arrangement	8,512			—			—
ROU assets obtained in exchange for lease liabilities:
Operating leases		$66,914			$—			$—
Financing leases	2,197			—			—

(1) The Company did not pay any federal income tax for any of the years in the three year period ending December 31, 2019.

Earnings per Share

The Company’s basic net income attributable to common shareholders per common share is based on the weighted average number of shares of common stock outstanding for the period. Diluted net income attributable to common shareholders per common share is calculated using the treasury stock method and is based on the weighted average number of common shares and all potentially dilutive common shares outstanding during the year which include RSU Equity Awards and common stock warrants. See “Note 6 - Earnings Per Share” for further discussion.

Industry Segment and Geographic Information

The Company operates in one industry segment, which is the exploration, development, and production of crude oil, NGLs, and natural gas. All of the Company’s operations are located in the United States and currently all revenues are attributable to customers located in the United States.

Recently Adopted Accounting Standards

Leases. In February 2016, the FASB issued ASU No. 2016-02, Leases (Topic 842): Amendments to the FASB Accounting Standards Codification. In January 2018, the FASB issued ASU No. 2018-01, Leases (Topic 842): Land Easement Practical Expedient for Transition to Topic 842. In July 2018, the FASB issued ASU No. 2018-11, Leases (Topic 842): Targeted Improvements. In March 2019, the FASB issued ASU No. 2019-01, Leases (Topic 842): Codification Improvements. Together these related amendments to GAAP represent ASC Topic 842, Leases (“ASC 842”).

Effective January 1, 2019, the Company adopted ASU 842, using the modified retrospective approach and did not have a cumulative-effect adjustment in retained earnings as a result of the adoption. ASC 842 requires lessees to recognize a liability representing the obligation to make lease payments and a related right-of-use (“ROU”) asset for virtually all lease transactions and disclose key quantitative and qualitative information about leasing arrangements. However, ASC 842 does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. The Company engaged a third-party consultant to assist with assessing its existing contracts, as well as future potential contracts, and to determine the impact of its application on its consolidated financial statements and related disclosures. The contract evaluation process included review of drilling rig contracts, office facility leases, compressors, field vehicles and equipment, general corporate leased equipment, and other existing arrangements to support its operations that may contain a lease component.

Upon adoption, the Company implemented policy elections and practical expedients which include the following:

• package of practical expedients which allows the Company to forego reassessing contracts that commenced prior to adoption that were properly evaluated under legacy lease accounting guidance

• excluding ROU assets and lease liabilities for leases with terms that are less than one year;

• combining lease and non-lease components and accounting for them as a single lease (elected by asset class);

• excluding land easements that existed or expired prior to adoption; and

• policy election that eliminates the need for adjusting prior period comparable financial statements prepared under legacy lease accounting guidance.

Through the implementation process, the Company evaluated each of its lease arrangements and enhanced its systems to track and calculate additional information required upon adoption of this standard. Adoption of ASC 842 did not materially change the Company’s consolidated statements of operations or consolidated statements of cash flows. See “Note 13 - Leases” for further discussion.

Recently Issued ASUs

None that are expected to have a material impact on our financial statements.

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Property and Equipment, Net (Schedule Of Property And Equipment) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Oil and natural gas properties, full cost accounting method
Evaluated properties	$ 7,203,482	$ 4,585,020
Accumulated depreciation, depletion, amortization and impairments	(2,520,488)	(2,270,675)
Net evaluated oil and natural gas properties	4,682,994	2,314,345
Unevaluated properties
Unevaluated leasehold and seismic costs	1,843,725	1,316,190
Capitalized interest	142,399	88,323
Total unevaluated properties	1,986,124	1,404,513
Total oil and natural gas properties, net	6,669,118	3,718,858
Other property and equipment	67,202	38,463
Accumulated depreciation	(31,949)	(16,562)
Other property and equipment, net	$ 35,253	$ 21,901

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Stockholders' Equity (Details) - USD ($)				12 Months Ended
	Jun. 18, 2019	May 30, 2018	Dec. 19, 2016	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 20, 2019
Class of Stock [Line Items]
Preferred stock dividend				$ 3,997,000	$ 7,295,000	$ 7,295,000
Issuance of common stock				0	$ 287,988,000	$ 0
Common Stock
Class of Stock [Line Items]
Authorized amount				$ 525,000,000			$ 300,000,000
Shares of common stock issued in public offering (in shares)		25,300,000	40,000,000.0
Issuance of common stock		$ 288,000,000.0	$ 634,900,000
Series A Preferred Stock
Class of Stock [Line Items]
Preferred stock cumulative cash dividends rate				10.00%
Preferred stock, liquidation preference (in dollars per share)	$ 50.00			$ 50.00	$ 50.00
Preferred stock, dividend rate (in dollars per share)				$ 5.00
Accrued and unpaid dividends (in dollars per share)	0.24
Redemption price (in dollars per share)	$ 50.24
Redemption amount	$ 73,000,000.0
Loss on redemption	8,300,000
Redemption date carrying value	$ 64,700,000

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Asset Retirement Obligations (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Asset retirement obligations at beginning of period	$ 14,292	$ 6,020
Accretion expense	945	874
Liabilities incurred	615	973
Increase due to acquisition of oil and gas properties	26,107	570
Liabilities settled	(3,394)	(1,288)
Dispositions	(1,776)	(614)
Revisions to estimates	12,944	7,757
Asset retirement obligations, end of period	49,733	14,292
Less: Current asset retirement obligations	(873)	(3,887)
Long-term asset retirement obligations	48,860	10,405
Restricted Investments
Restricted investments	$ 3,500	$ 3,400

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Share-Based Compensation (Narrative) (Details) $ in Thousands		12 Months Ended
	May 10, 2018 shares	Dec. 31, 2019 USD ($) shares	Dec. 31, 2018 USD ($) shares	Dec. 31, 2017 USD ($) shares	Dec. 20, 2019
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards		$ 1,425	$ 4,990	$ 13,173
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage				142.00%
Fair value of shares vested		7,300	$ 6,300	$ 9,000
Unrecognized compensation cost related to unvested awards		$ 15,100
Weighted average period over which expense is expected to be recognized		1 year 3 months 18 days
Vested in period (in shares) | shares		1,062,000	506,000	797,000
RSU equity awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		0.00%
RSU equity awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		200.00%
Performance-based RSU
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested		$ 4,300	$ 3,500	$ 2,600
Cash-settleable RSU awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Unrecognized compensation cost related to unvested awards		$ 1,100
Weighted average period over which expense is expected to be recognized		1 year 6 months
Vested in period (in shares) | shares		164,000	276,000	379,000
Cash-settleable RSU awards | Vesting Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		0.00%
Cash-settleable RSU awards | Vesting Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		200.00%
Market-based Cash-settleable RSUs Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage		100.00%
Vested in period (in shares) | shares		147,492	207,261
Cash-settleable restricted stock unit awards		$ 700
Market-based Cash-settleable RSUs Awards | Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage			100.00%
Market-based Cash-settleable RSUs Awards | Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based compensation arrangement vesting rights, percentage			163.00%
Market-based Cash-settleable RSUs Awards | Vested at between 100% to 163%
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Payments to settle vested liability share-based awards		$ 1,300	$ 100
Non-Market Based Cash-settleable RSU Awards
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vested in period (in shares) | shares		16,600	129,753
Payments to settle vested liability share-based awards		$ 100	$ 1,800
Cash-settled SARs
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Fair value of shares vested		4,600
Unrecognized compensation cost related to unvested awards		$ 5,000
Carrizo
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Exchange ratio (in shares)		1.75			1.75
2018 Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized (in shares) | shares	9,400,000	10,722,742
Increase (decrease) in shares | shares	1,322,742
Number of shares available for grant (in shares) | shares		13,814,216

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Income Taxes (Reconciliation) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income before income taxes	$ 103,229	$ 308,470	$ 121,697
Income tax expense computed at the statutory federal income tax rate	21,678	64,779	42,594
State income tax expense, net of federal benefit	1,253	3,568	1,273
Equity based compensation	1,222	(494)	0
Non-deductible compensation	90	1,209	0
Non-deductible merger expenses	5,537	0	0
Statutory depletion carryforward	5,381	0	0
Other	140	168	0
Change in valuation allowance	0	(61,120)	(42,594)
Income tax expense	$ 35,301	$ 8,110	$ 1,273

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Leases (Cost) (Details) $ in Thousands	12 Months Ended
	Dec. 31, 2019 USD ($)
Components of Lease Costs
Finance lease costs	$ 92
Finance lease costs	82
Interest on lease liabilities	10
Operating lease cost	38,076
Impairment of ROU assets	16,209
Short-term lease cost	3,640
Variable lease costs	0
Total lease costs	58,017
Costs associated with drilling rigs and are capitalized	34,900
Carrizo
Components of Lease Costs
Impairment of ROU assets	$ 16,200

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Share-Based Compensation (Summary of Liability for Cash-Settled RSU Awards) (Details) - Cash-settleable RSU awards - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Other current liabilities	$ 966	$ 1,390
Other long-term liabilities	2,089	2,067
Total Cash-Settled RSU Awards	$ 3,055	$ 3,457

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Derivative Instruments and Hedging Activities

12 Months Ended

Dec. 31, 2019

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging Activities

Derivative Instruments and Hedging Activities

Objectives and strategies for using derivative instruments

The Company is exposed to fluctuations in oil and natural gas 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 production. The Company utilizes a mix of collars, swaps, and put and call options 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 risk and offsetting

The use of derivative instruments exposes the Company to the risk that a counterparty will be unable to meet its commitments. 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 9 - Fair Value Measurements” for further discussion.

The Company executes commodity derivative contracts under master agreements with netting provisions that provide for offsetting assets against liabilities. 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.

Financial statement presentation and settlements

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.

Contingent consideration arrangements

Ranger Divestiture. The Company’s Ranger Divestiture provides for potential contingent consideration to be received by the Company if commodity prices exceed specified thresholds in each of the next several years. See “Note 4 - Acquisitions and Divestitures” and “Note 9 - Fair Value Measurements” for further discussion. This contingent consideration arrangement is summarized in the table below (in thousands except for per Bbl amounts):

Year

Threshold (1)

Contingent Receipt - Annual

Threshold (1)

Contingent Receipt - Annual

Period Cash Flow Occurs

Statement of Cash Flows Presentation

Remaining Contingent Receipt - Aggregate Limit (3)

Divestiture Date Fair Value

$8,512

Pending Settlement

2019

Greater than $60/Bbl, less than $65/Bbl

$—

Equal to or greater than $65/Bbl

$—

1Q20

N/A

Remaining Potential Settlements

2020-2021

Greater than $60/Bbl, less than $65/Bbl

$9,000

Equal to or greater than $65/Bbl

$20,833

(2)

(2)

$60,000

(1) The price used to determine whether the specified thresholds have been met is the average of the final monthly settlements for each month during each annual period end for NYMEX Light Sweet Crude Oil Futures, as reported by the CME Group Inc.

(2) Cash received for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the divestiture date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, $8.5 million of the next contingent receipt will be presented in cash flows from financing activities with the remainder, as well as all subsequent contingent receipts, presented in cash flows from operating activities.

(3) The specified pricing threshold for 2019 was not met. As such, approximately $41.5 million remains for potential settlements in future years.

As a result of the Carrizo Acquisition, the Company assumed all contingent consideration arrangements previously entered into by Carrizo. These contingent consideration arrangements are summarized below:

Contingent ExL Consideration

	Year	Threshold (1)		Period Cash Flow Occurs	Statement of Cash Flows Presentation	Contingent Payment - Annual			Remaining Contingent Payments - Aggregate Limit				Acquisition Date Fair Value
						(In thousands)
														($69,171	)
Pending Settlement	2019		$50.00	1Q20	Investing		($50,000	)
Remaining Potential Settlements	2020-2021		$50.00	(2)	(2)		($50,000	)		($75,000	)	(3)

(1) The price used to determine whether the specified threshold for each year has been met is the average daily closing spot price per barrel of WTI crude oil as measured by the U.S. Energy Information Administration (“U.S. EIA”).

(2) Cash paid for settlements of contingent consideration arrangements are classified as cash flows from financing activities up to the acquisition date fair value with any excess classified as cash flows from operating activities. Therefore, if the commodity price threshold is reached, all of the next contingent payment will be presented in cash flows from financing activities.

(3) In January 2020, the Company paid $50.0 million as the specified pricing threshold was met. Only $25.0 million remains for potential settlements in future years.

Additionally, as part of the Carrizo Acquisition, the Company acquired contingent consideration arrangements where the Company could receive payments if certain pricing thresholds are met, which range between $53.00 - $60.00 per barrel of oil or $3.18 - $3.30 per MMBtu of natural gas. In January 2020, the Company received $10.0 million as the specified pricing thresholds were met for certain of the contingent consideration arrangements. As such, the aggregate limit of the remaining contingent receipts is $13.0 million and would be settled in January 2021 based on the specified pricing thresholds for 2020.

See “Note 18 - Subsequent Events” for further discussion of the Company’s actual settlements of its contingent consideration arrangements subsequent to December 31, 2019.

Derivatives not designated as hedging instruments

The Company records its derivative instruments at fair value in the consolidated balance sheets and records changes in fair value as “(Gain) loss on derivative contracts” in the consolidated statements of operations. Settlements are also recorded as a gain or loss on derivative contracts in the consolidated statements of operations.

As previously discussed, the Company’s commodity derivative contracts are subject to master netting arrangements. The Company’s policy is to present the fair value of derivative contracts on a net basis in the consolidated balance sheet. The following presents the impact of this presentation to the Company’s recognized assets and liabilities for the periods indicated:

໿

	As of December 31, 2019
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Commodity derivative instruments		$26,849			($17,511	)		$9,338
Contingent consideration arrangements	16,718			—			16,718
Fair value of derivatives - current		$43,567			($17,511	)		$26,056
Commodity derivative instruments	—			—			—
Contingent consideration arrangements	9,216			—			9,216
Fair value of derivatives - non current		$9,216			$—			$9,216
Commodity derivative instruments		($38,708	)		$17,511			($21,197	)
Contingent consideration arrangements	(50,000		)	—			(50,000		)
Fair value of derivatives - current		($88,708	)		$17,511			($71,197	)
Commodity derivative instruments	(12,935		)	—			(12,935		)
Contingent consideration arrangements	(19,760		)	—			(19,760		)
Fair value of derivatives - non current		($32,695	)		$—			($32,695	)

	As of December 31, 2018
	Presented without						As Presented with
	Effects of Netting			Effects of Netting			Effects of Netting
	(In thousands)
Fair value of derivatives - current		$78,091			($12,977	)		$65,114
Fair value of derivatives - current		($23,457	)		$12,977			($10,480	)
Fair value of derivatives - non current	(7,440		)	—			(7,440		)

The components of “(Gain) loss on derivative contracts” are as follows for the respective periods:

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	Years Ended December 31,
	2019			2018			2017
	(In thousands)
Oil derivatives
Net gain (loss) on settlements		($11,188	)		($27,510	)		($9,067	)
Net gain (loss) on fair value adjustments	(62,125		)	72,973			(11,426		)
Total gain (loss) on oil derivatives	(73,313		)	45,463			(20,493		)
Natural gas derivatives
Net gain (loss) on settlements	7,399			238			594
Net gain (loss) on fair value adjustments	1,490			2,843			998
Total gain (loss) on natural gas derivatives	8,889			3,081			1,592
Contingent consideration arrangements
Net gain (loss) on fair value adjustments	2,315			—			—
Total gain (loss) on derivative contracts		($62,109	)		$48,544			($18,901	)

Derivative positions

Listed in the tables below are the outstanding oil and natural gas derivative contracts as of December 31, 2019:

	For the Full Year of					For the Full Year of
Oil contracts (WTI)	2020					2021
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	13,176,000					—
Weighted average price per Bbl
Ceiling (short call)		$65.28				$	—
Floor (long put)		$55.38				$	—
Floor (short put)		$45.08				$	—
Short call contracts
Total volume (Bbls)	1,674,450			(1	)	4,825,300		(1)
Weighted average price per Bbl		$75.98					$63.62
Swap contracts
Total volume (Bbls)	1,303,900					—
Weighted average price per Bbl		$55.19					$—
Swap contracts with short puts
Total volume (Bbls)	2,196,000					—
Weighted average price per Bbl
Swap		$56.06					$—
Floor (short put)		$42.50					$—
Oil contracts (Brent ICE)
Collar contracts with short puts (three-way collars)
Total volume (Bbls)	837,500					—
Weighted average price per Bbl
Ceiling (short call)		$70.00					$—
Floor (long put)		$58.24					$—
Floor (short put)		$50.00					$—
Oil contracts (Midland basis differential)
Swap contracts
Total volume (Bbls)	8,476,700					4,015,100
Weighted average price per Bbl		($1.47	)				$0.40
Oil contracts (Argus Houston MEH basis differential)
Swap contracts
Total volume (Bbls)	1,439,205					—
Weighted average price per Bbl		$2.40					$—
Oil contracts (Argus Houston MEH swaps)
Swap contracts
Total volume (Bbls)	504,500					—
Weighted average price per Bbl		$58.22					$—
Natural gas contracts (Henry Hub)
Collar contracts (three-way collars)
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu
Ceiling (short call)		$2.75					$—
Floor (long put)		$2.50					$—
Floor (short put)		$2.00					$—
Swap contracts
Total volume (MMBtu)	3,660,000					—
Weighted average price per MMBtu		$2.48					$—
Short call contracts
Total volume (MMBtu)	12,078,000					7,300,000
Weighted average price per MMBtu		$3.50					$3.09
Natural gas contracts (Waha basis differential)
Swap contracts
Total volume (MMBtu)	21,596,000					—
Weighted average price per MMBtu		($1.04	)				$—

(1)

Premiums from the sale of call options were used to increase the fixed price of certain simultaneously executed price swaps and three-way collars.

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Acquisitions and Divestitures

12 Months Ended

Dec. 31, 2019

Business Combinations [Abstract]

Acquisitions and Divestitures

Acquisitions and Divestitures

2019 Acquisitions and Divestitures

Carrizo Oil & Gas, Inc. Merger. On December 20, 2019, the Company completed its acquisition of Carrizo in an all-stock transaction (the “Merger” or the “Carrizo Acquisition”). Under the terms of the Merger, each outstanding share of Carrizo common stock was converted into 1.75 shares of the Company’s common stock. The Company issued approximately 168.2 million shares of common stock at a price of $4.55 per share, resulting in total consideration paid by the Company to the former Carrizo shareholders of approximately $765.4 million. In connection with the closing of the Merger, the Company funded the redemption of Carrizo’s 8.875% Preferred Stock, repaid the outstanding principal under Carrizo’s revolving credit facility and assumed all of Carrizo’s senior notes. See “Note 7 - Borrowings” for further details.

The Merger was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. Certain data necessary to complete the purchase price allocation is not yet available, including final tax returns that provide the underlying tax basis of Carrizo’s assets and liabilities. The company expects to complete the purchase price allocation during the 12-month period following the acquisition date.

The following table sets forth the Company’s preliminary allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Preliminary Purchase Price Allocation
	(In thousands)
Consideration:
Fair value of the Company’s common stock issued		$765,373
Total consideration		$765,373
Liabilities:
Accounts payable		$37,657
Revenues and royalties payable	52,449
Operating lease liabilities - current	29,924
Fair value of derivatives - current	61,015
Other current liabilities	82,084
Long-term debt	1,984,135
Operating lease liabilities - non-current	30,070
Asset retirement obligation	26,151
Fair value of derivatives - non-current	26,960
Other long-term liabilities	17,260
Common stock warrants	10,029
Total liabilities assumed		$2,357,734
Assets:
Accounts receivable, net		$48,479
Fair value of derivatives - current	17,451
Other current assets	4,945
Evaluated oil and natural gas properties	2,133,280
Unevaluated properties	682,928
Other property and equipment	9,614
Fair value of derivatives - non-current	4,518
Deferred tax asset	159,320
Operating lease right-of-use-assets	59,994
Other long term assets	2,578
Total assets acquired		$3,123,107

Approximately $28.6 million of revenues and $7.0 million of direct operating expenses attributed to the Carrizo Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on December 20, 2019 through December 31, 2019.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma combined condensed financial data for the years ended December 31, 2019 and 2018 was derived from the historical financial statements of the Company giving effect to the Merger, as if it had occurred on January 1, 2018. The below information reflects pro forma adjustments for the issuance of the Company’s common stock in exchange for Carrizo’s outstanding shares of common stock, as well as pro forma adjustments based on available information and certain assumptions that the Company believes are reasonable, including (i) the Company’s common stock issued to convert Carrizo’s outstanding shares of common stock and equity awards as of the closing date of the Merger, (ii) the depletion of Carrizo’s fair-valued proved oil and natural gas properties and (iii) the estimated tax impacts of the pro forma adjustments.

Additionally, pro forma earnings were adjusted to exclude acquisition-related costs incurred by the Company of approximately $58.8 million for the year ended December 31, 2019 and acquisition-related costs incurred by Carrizo that totaled approximately $15.6 million for the year ended December 31, 2019. The pro forma results of operations do not include any cost savings or other synergies that may result from the Merger or any estimated costs that have been or will be incurred by the Company to integrate the Carrizo assets. The pro forma financial data does not include the pro forma results of operations for any other acquisitions made during the periods presented, as they were primarily acreage acquisitions and their results were not deemed material.

The pro forma consolidated statements of operations data has been included for comparative purposes only and is not necessarily indicative of the results that might have occurred had the Merger taken place on January 1, 2018 and is not intended to be a projection of future results.

	Years Ended December 31,
	2019		2018
	(In thousands)
Revenues		$1,620,357		$1,661,171
Income from operations	614,668		767,628
Net income	369,777		734,527
Basic earnings per common share	0.89			$1.87
Diluted earnings per common share	0.89			$1.87

During 2019, in conjunction with the Carrizo Acquisition, the Company incurred costs totaling $74.4 million comprised of severance costs of $28.8 million and other merger and integration expenses of $45.6 million. As of December 31, 2019, $52.4 million remained accrued and is included as a component of “Accounts payable and accrued liabilities” in the consolidated balance sheets.

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 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 includes approximately 9,850 net Wolfcamp acres with an average 66% working interest. The net cash proceeds were recognized as a reduction of evaluated oil and gas properties with no gain or loss recognized.

2018 Acquisitions and Divestitures

On August 31, 2018, the Company completed the acquisition of approximately 28,000 net surface acres in the Spur operating area, located in the Delaware Basin, from Cimarex Energy Company, for a net cash consideration of approximately $539.5 million (the “Delaware Asset Acquisition”). The Company funded the Delaware Asset Acquisition with net proceeds from both the common stock offering completed on May 30, 2018 and the issuance of the 6.375% Senior Notes. See “Note 7 - Borrowings” and “Note 11 - Stockholders’ Equity” for further details of these offerings.

The Delaware Asset Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$253,089
Unevaluated properties	287,000
Total oil and natural gas properties		$540,089
Total assets acquired		$540,089
Liabilities
Asset retirement obligations		($570	)
Total liabilities assumed		($570	)
Net Assets Acquired		$539,519

Approximately $27.3 million of revenues and $9.9 million of direct operating expenses attributed to the Delaware Asset Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on August 31, 2018 through December 31, 2018.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the years ended December 31, 2018 and 2017, assuming the Delaware Asset Acquisition had been completed as of January 1, 2017, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Delaware Asset Acquisition.

	Years Ended December 31,
	2018		2017
	(In thousands)
Revenues		$669,236		$469,896
Income from operations	299,090		209,723
Net income	324,318		181,406
Basic earnings per common share	$1.49		$0.90
Diluted earnings per common share	$1.49		$0.90

Other. In addition, the Company completed various acquisitions of additional working interests and mineral rights, and associated production volumes, in the Company’s existing core operating areas within the Permian Basin. In the first quarter of 2018, the Company completed acquisitions within Monarch and WildHorse operating areas for aggregate net cash consideration of approximately $37.8 million. In the fourth quarter of 2018, the Company completed acquisitions of leasehold interests and mineral rights within its WildHorse and Spur operating areas for net cash consideration of approximately $87.9 million.

The Company did not have any material divestitures for the year ended December 31, 2018.

2017 Acquisitions and Divestitures

Ameredev Acquisition. On February 13, 2017, the Company completed the acquisition of 29,175 gross (16,688 net) acres in the Delaware Basin, primarily located in Ward and Pecos Counties, Texas from American Resource Development, LLC, for total cash consideration of $646.6 million, excluding customary purchase price adjustments (the “Ameredev Acquisition”). The Company partially funded the Ameredev Acquisition with net proceeds from the common stock offering completed on December 19, 2016. The Company obtained an 82% average working interest (75% average net revenue interest) in the properties acquired in the Ameredev Acquisition.

The Ameredev Acquisition was accounted for as a business combination, therefore, the purchase price was allocated to the assets acquired and the liabilities assumed based on their estimated acquisition date fair values based on then currently available information. A combination of a discounted cash flow model and market data was used by a third-party specialist in determining the fair value of the oil and gas properties. Significant inputs into the calculation included future commodity prices, estimated volumes of oil and gas reserves, expectations for timing and amount of future development and operating costs, future plugging and abandonment costs and a risk adjusted discount rate. The following table sets forth the Company’s allocation of the purchase price to the assets acquired and liabilities assumed as of the acquisition date.

	Purchase Price Allocation
	(In thousands)
Assets
Oil and natural gas properties
Evaluated properties		$137,368
Unevaluated properties	509,359
Total oil and natural gas properties		$646,727
Total assets acquired		$646,727
Liabilities
Asset retirement obligations		($168	)
Total liabilities assumed		($168	)
Net Assets Acquired		$646,559

Approximately $36.1 million of revenues and $8.5 million of direct operating expenses attributed to the Ameredev Acquisition are included in the Company’s consolidated statements of operations for the period from the closing date on February 13, 2017 through December 31, 2017.

Pro Forma Operating Results (Unaudited). The following unaudited pro forma financial information presents a summary of the Company’s consolidated results of operations for the year ended December 31, 2017, assuming the Ameredev Acquisition had been completed as of January 1, 2016, including adjustments to reflect the acquisition date fair values assigned to the assets acquired and liabilities assumed. The pro forma financial information does not purport to represent what the actual results of operations would have been had the transactions been completed as of the date assumed, nor is this information necessarily indicative of future consolidated results of operations. The Company believes the assumptions used provide a reasonable basis for reflecting the significant pro forma effects directly attributable to the Ameredev Acquisition.

	Year Ended December 31, 2017
	(In thousands)
Revenues		$369,527
Income from operations	144,104
Net income	115,787
Basic earnings per common share		$0.57
Diluted earnings per common share		$0.57

Other. On June 5, 2017, the Company completed the acquisition of 7,031 gross (2,488 net) acres in the Delaware Basin, located near the acreage acquired in the Ameredev Acquisition discussed above, for aggregate net cash consideration of approximately $52.0 million. The Company funded the cash purchase price with available cash and proceeds from the issuance of an additional $200.0 million of its 6.125% Senior Notes. See “Note 7 - Borrowings” for further details of this offering.

The Company did not have any material divestitures for the year ended December 31, 2017.

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Income Taxes

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes 

The components of the Company’s income tax expense are as follows:

	Years Ended December 31,
	2019		2018		2017
	(In thousands)
Current
Federal		$—		$—		($48	)
State	220		—		—
Total current income tax expense (benefit)	220		—		(48		)
Deferred
Federal	33,584		3,594		(45		)
State	1,497		4,516		1,366
Total deferred income tax expense	35,081		8,110		1,321
Total income tax expense		$35,301		$8,110		$1,273

A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows:

	Years Ended December 31,
	2019		2018			2017
Income before income taxes		$103,229		$308,470			$121,697
Income tax expense computed at the statutory federal income tax rate	21,678		64,779			42,594
State income tax expense, net of federal benefit	1,253		3,568			1,273
Equity based compensation	1,222		(494		)	—
Non-deductible compensation	90		1,209			—
Non-deductible merger expenses	5,537		—			—
Statutory depletion carryforward	5,381		—			—
Other	140		168			—
Change in valuation allowance	—		(61,120		)	(42,594		)
Income tax expense		$35,301		$8,110			$1,273

At December 31, 2019, the Company recorded a tax expense of $5.5 million associated with non-deductible merger expenses from the Carrizo Acquisition which primarily relate to non-deductible executive compensation expenses and transaction costs that are inherently facilitative in nature and permanently capitalized for tax purposes.

The Company recorded an income tax expense of $5.4 million related to the statutory depletion carryforward of $24.9 million. The percentage depletion deductions are in excess of the Company’s net depletable basis and can be carried forward indefinitely. The tax benefit for the special deduction will be recognized in the year the carryforward is deducted on the federal tax return.

As of December 31, 2019 and 2018, the net deferred income tax assets and liabilities are comprised of the following:

	As of December 31,
	2019			2018
	(In thousands)
Deferred tax assets
Federal net operating loss carryforward		$110,703			$151,497
Interest expense carryforward	—			7,335
Statutory depletion carryforward	—			5,381
Asset retirement obligations	9,981			2,347
Derivative asset	14,823			—
Unvested RSU equity awards	4,928			2,751
Operating lease right-of-use assets	29,897			—
Other	10,445			991
Total deferred tax assets		$180,777			$170,302
Deferred income tax valuation allowance	—			—
Net deferred tax assets		$180,777			$170,302
Deferred tax liability
Oil and natural gas properties		($38,546	)		($169,682	)
Derivative liability	—			(10,184		)
Operating lease liabilities	(26,511		)	—
Total deferred tax liability		($65,057	)		($179,866	)
Net deferred tax asset (liability)		$115,720			($9,564	)

For federal income tax purposes, the Carrizo Acquisition qualified as a tax-free merger whereby the Company acquired carryover tax basis in Carrizo’s assets and liabilities. The Company recorded an opening balance sheet deferred tax asset of $159.3 million related to tax attributes acquired from Carrizo. The acquired income tax attributes primarily consist of future deductions related to oil and gas properties, derivative assets, and federal net operating losses (“NOLs”). The acquired NOLs are subject to an annual limitation under Internal Revenue Code Section 382 and the Company reduced the total NOL balance and associated deferred tax asset for the NOLs to the amount expected to be fully utilized prior to expirations. The Company expects that these tax attributes will be fully utilized prior to expiration.

Due to the issuance of common stock associated with the Carrizo acquisition, the Company incurred a cumulative ownership 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, 2019, the Company had approximately $527.2 million of NOLs, including $288.2 million acquired from Carrizo, of which approximately $496.5 million expire between 2035 and 2037 and $30.7 million have an indefinite carryforward life. The Company expects that the NOL balance will be fully utilized prior to expiration.

Management 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. At December 31, 2019, management considered all factors including the expected reversal of deferred tax liabilities (including the impact of available carryforward periods), historical operating income tax planning strategies and projected future taxable income and determined that it is more likely than not that the Company will realize its remaining deferred tax assets.

The Company had no significant unrecognized tax benefits at December 31, 2019. 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. In the Company’s major tax jurisdictions, the earliest year open to examination is 2015.

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2019

Earnings Per Share [Abstract]

Computation of Basic and Diluted Earnings Per Share

The following table sets forth the computation of basic and diluted earnings per share:

	Years Ended December 31,
	2019			2018			2017
	(In thousands, except per share amounts)
Net income		$67,928			$300,360			$120,424
Preferred stock dividends	(3,997		)	(7,295		)	(7,295		)
Loss on redemption of preferred stock	(8,304		)	—			—
Income available to common stockholders		$55,627			$293,065			$113,129
Basic weighted average common shares outstanding	233,140			216,941			201,526
Dilutive impact of restricted stock	410			655			576
Diluted weighted average common shares outstanding	233,550			217,596			202,102
Income Available to Common Stockholders Per Common Share
Basic		$0.24			$1.35			$0.56
Diluted		$0.24			$1.35			$0.56
Restricted stock (1)	998			89			16

(1)

Shares excluded from the diluted earnings per share calculation because their effect would be anti-dilutive.

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Share-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2019

Share-based Payment Arrangement [Abstract]

Schedule of Restricted Stock Units Activity

The following table summarizes RSU Equity Award activity for the years ended December 31, 2019, 2018 and 2017:

	RSU Equity Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	1,448			$10.81
Granted (1) (2)	1,173			$12.25
Vested (3)	(797	)		$11.35
Forfeited	(34	)		$9.57
Unvested at the end of the period	1,790			$11.54
For the Year Ended December 31, 2018
Unvested at the beginning of the period	1,790			$11.54
Granted (1)	872			$13.89
Vested (3)	(506	)		$9.56
Forfeited	(53	)		$11.43
Unvested at the end of the period	2,103			$13.24
For the Year Ended December 31, 2019
Unvested at the beginning of the period	2,103			$13.24
Granted (1)	1,881			$8.60
Vested (3)	(1,062	)		$12.35
Forfeited	(227	)		$10.59
Unvested at the end of the period	2,695			$10.57

(1) Includes 399,425, 208,000 and 89,000 target performance-based RSU Equity Awards that will vest at a range of 0% - 200% for the years ended December 31, 2019, 2018 and 2017, respectively.

(2) Includes 73,000 performance based RSU Equity Awards that were granted and subsequently vested at 142% of target at issuance in 2017.

(3)

The fair value of shares vested was $7.3 million, $6.3 million and $9.0 million during the years ended December 31, 2019, 2018 and 2017, respectively.

Schedule of Shares that Vested and Did Not Vest

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	2019		2018		2017
Vesting Multiplier	100	%	142	%	142% - 200%
Target	88,790		83,002		258,406
Vested at end of performance period	88,790		117,862		441,232
Did not vest at end of performance period	—		—		—

Schedule of Fair Value Inputs

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, 2019, 2018 and 2017:

	Years Ended December 31,
Performance-based Awards	2019		2018		2017
Number of simulations	100,000		100,000		100,000
Expected term (in years)	2.9		2.6		2.6
Expected volatility	47.9	%	51.6	%	65.3	%
Risk-free interest rate	2.4	%	2.6	%	1.5	%
Dividend yield	—	%	—	%	—	%
Grant date fair value per performance-based RSU Equity Award	$10.78		$16.66		$16.06

The following table summarizes the assumptions used, the resulting acquisition date fair value per Cash SAR, and the expiration dates for the grants that occurred during periods presented below:

	2019		2018		2017		2016
Fair Value Inputs
Expected term (in years)	5.4		4.5		1.9		1.1
Expected volatility	60.7	%	56.9	%	58.6	%	68.1	%
Risk-free interest rate	1.7	%	1.7	%	1.6	%	1.5	%
Dividend yield	—	%	—	%	—	%	—	%
Acquisition date fair value per Cash SAR	$2.11		$1.42		$0.21		$0.10
Expiration date	March 17, 2026		March 17, 2025		March 23, 2022		March 17, 2021

Schedule of Cash-Settleable RSUs

The table below summarizes the Cash-Settled RSU Award activity for the years ended December 31, 2019, 2018 and 2017:

	Cash-Settled RSU Awards (in thousands)		Weighted Average Grant-Date Fair Value per Share
For the Year Ended December 31, 2017
Unvested at the beginning of the period	734			$8.87
Granted	283			$12.13
Vested	(379	)		$9.61
Forfeited	(13	)		$9.54
Unvested at the end of the period	625			$9.88
For the Year Ended December 31, 2018
Unvested at the beginning of the period	625			$9.88
Granted	348			$14.16
Vested	(276	)		$9.04
Forfeited	(19	)		$12.05
Unvested at the end of the period	678			$12.36
For the Year Ended December 31, 2019
Unvested at the beginning of the period	678			$12.36
Granted	424			$8.14
Vested	(164	)		$12.02
Forfeited	(83	)		$11.58
Unvested at the end of the period	855			$10.41

Summary of Liability for Cash-Settled RSU Awards

The following table summarizes the Company’s liability for Cash-Settled RSU Awards and the classification in the consolidated balance sheets for the periods indicated:

	December 31,
	2019		2018
Other current liabilities		$966		$1,390
Other long-term liabilities	2,089		2,067
Total Cash-Settled RSU Awards		$3,055		$3,457

Schedule of Performance-Based Cash-Settled RSUs Awards

As of December 31, 2019, the Company had the following performance-based Cash-Settled RSU Awards outstanding:

	Target Awards Outstanding	Potential Minimum Units Vesting	Potential Maximum Units Vesting
	(In thousands)
Vesting in 2020	292	—	586
Vesting in 2021	373	—	745
Vesting in 2022	—	—	—
Other	24	24	24
Total Cash-Settled RSU Awards	689	24	1,355

Schedule of Cash-Settled SARs

The table below summarizes the Cash SAR activity for the year ended December 31, 2019.

	Stock Appreciation Rights	Weighted Average Exercise Prices		Weighted Average Remaining Life (In years)	Aggregate Intrinsic Value (In millions)
For the Year Ended December 31, 2019
Outstanding, beginning of period	—		$—
Granted	—		$—
Reissued	3,677,955		$10.03
Exercised	—		$—
Forfeited	—		$—
Expired	—		$—
Outstanding, end of period	3,677,955		$10.03	4.4		$—
Vested, end of period	3,677,955		$10.03	0		$—
Vested and exercisable, end of period	—		$—	0		$—

Schedule of Share-based Compensation Expense

The following table presents share-based compensation expense for each respective period:

	Years Ended December 31,
	2019				2018				2017
Share-based compensation cost for:	Equity		Liability		Equity		Liability		Equity		Liability
RSU Equity Awards (1)		$14,322		$—		$9,460		$—		$10,225		$—
Cash-Settled RSU Awards (1)	—		1,021		—		336		—		4,294
Cash SARs	—		443		—		—		—		—
Total share-based compensation cost (2)		$14,322		$1,464		$9,460		$336		$10,225		$4,294

(1) Includes the settlement of the outstanding share-based award agreements of the Company’s former Chief Executive Officer, resulting in $6.4 million recorded on the consolidated statements of operations as settled share-based awards for the year ended December 31, 2017.

(2)

The portion of this share-based compensation cost that was included in “General and administrative” totaled $11.1 million, $6.4 million and $5.0 million for the years ended December 31, 2019, 2018 and 2017, respectively, and the portion capitalized to oil and gas properties was $4.7 million, $3.4 million and $3.2 million for the years ended December 31, 2019, 2018, and 2017, respectively.

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Supplemental Quarterly Financial Information (Unaudited)

12 Months Ended

Dec. 31, 2019

Quarterly Financial Information Disclosure [Abstract]

Supplemental Quarterly Financial Information (Unaudited)

Supplemental Quarterly Financial Information (Unaudited)

The following is a summary of the unaudited quarterly financial data for the years ended December 31, 2019 and 2018:

2019	First Quarter (2)			Second Quarter (3)		Third Quarter (4)		Fourth Quarter (5)
	(In thousands, except per share amounts)
Total operating revenues		$153,047			$167,052		$155,378		$196,095
Income from operations	43,225			58,509		52,544		18,380
Net income (loss)	(19,543		)	55,180		55,834		(23,543		)
Income (loss) available to common stockholders	(21,367		)	53,357		47,180		(23,543		)
Income (loss) available to common stockholders per common share (1)
Basic		($0.09	)		$0.23		$0.21		($0.09	)
Diluted		($0.09	)		$0.23		$0.21		($0.09	)

2018	First Quarter		Second Quarter (6)		Third Quarter (7)		Fourth Quarter (8)
	(In thousands, except per share amounts)
Total operating revenues		$127,440		$137,075		$161,214		$161,895
Income from operations	60,986		67,400		72,811		58,333
Net income	55,761		50,474		37,931		156,194
Income available to common stockholders	53,937		48,650		36,108		154,370
Income available to common stockholders per common share (1)
Basic		$0.27		$0.23		$0.16		$0.68
Diluted		$0.27		$0.23		$0.16		$0.68

(1) The sum of quarterly income (loss) available to common stockholders per common share does not agree with the total year income (loss) available to common stockholders per common share as each computation is based on the weighted average of common shares outstanding during the period.

(2) First quarter of 2019 included the following:

a. $67.3 million loss on derivative contracts

(3) Second quarter of 2019 included the following:

a. $14.0 million gain on derivative contracts

(4) Third quarter of 2019 included the following:

a. $21.8 million gain on derivative contracts

b. $5.9 million of merger and integration costs associated with the merger with Carrizo

c. $8.3 million loss on redemption of Preferred Stock

(5) Fourth quarter of 2019 included the following:

a. Activity from the Carrizo Acquisition subsequent to the December 20, 2019 closing date.

b. $68.4 million of merger and integration costs associated with the merger with Carrizo

c. $30.7 million loss on derivative contracts

d. $4.9 million loss on extinguishment of debt

(6) Second quarter of 2018 included the following:

a. $16.6 million loss on derivative contracts

(7) Third quarter of 2018 included the following:

a. $34.3 million loss on derivative contracts

(8) Fourth quarter of 2018 included the following:

a. 103.9 million gain on derivative contracts

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Accounts Payable and Accrued Liabilities

12 Months Ended

Dec. 31, 2019

Payables and Accruals [Abstract]

Accounts Payable and Accrued Liabilities

Accounts Payable and Accrued Liabilities

	As of December 31,
	2019		2018
	(In thousands)
Accounts payable		$238,758		$83,412
Revenues payable	145,816		94,114
Accrued capital expenditures	61,950		83,658
Accrued interest	36,295		24,665
Accrued severance (1)	28,803		—
Total accounts payable and accrued liabilities		$511,622		$285,849

(1)    See “Note 4 - Acquisitions and Divestitures” for further information regarding the Carrizo Acquisition.

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Commitments and Contingencies (Tables)

12 Months Ended

Dec. 31, 2019

Commitments and Contingencies Disclosure [Abstract]

Contractual Obligations

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 natural gas or produced water to be delivered, as of December 31, 2019.

	2020	2021	2022	2023	2024	2025 and Thereafter	Total
	(In thousands)
Operating leases	$12,423	$8,399	$4,363	$4,209	$4,110	$17,902	$51,406
Drilling rig contracts (1)	33,441	3,249	—	—	—	—	36,690
Delivery commitments (2)	9,563	13,437	10,980	11,553	12,417	39,298	97,248
Produced water disposal commitments (3)	14,947	14,968	11,933	4,387	1,570	1,840	49,645
Total	$70,374	$40,053	$27,276	$20,149	$18,097	$59,040	$234,989

(1) Drilling rig contracts 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.

(2) Delivery commitments represent contractual obligations we have entered into for certain gathering, processing and transportation service agreements which require minimum volumes of natural gas to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any natural gas.

(3)

Produced water disposal commitments represent contractual obligations we have entered into for certain service agreements which require minimum volumes of produced water to be delivered. The amounts in the table above reflect the aggregate undiscounted deficiency fees assuming no delivery of any produced water.

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Summary of Significant Accounting Policies (Narrative) (Details)	12 Months Ended
	Dec. 31, 2019 USD ($) segment	Dec. 31, 2018 USD ($)	Dec. 31, 2017 USD ($)
Accounting Policies [Line Items]
Computation of proved reserves, discount factor as percent	10.00%
Write-down of oil and natural gas properties	$ 0	$ 0	$ 0
Accumulated depreciation	31,949,000	16,562,000
Amortization of financing costs	2,907,000	2,483,000	2,150,000
Valuation allowance	$ 0	0
Number of operating segments | segment	1
Operating lease, liability	$ 79,946,000
Operating lease right-of-use assets	$ 63,908,000
RSU equity awards | Employees
Accounting Policies [Line Items]
Vesting period	3 years
RSU equity awards | Directors
Accounting Policies [Line Items]
Vesting period	1 year
Cash-settleable RSU awards
Accounting Policies [Line Items]
Vesting period	3 years
Minimum | Cash-settled SARs
Accounting Policies [Line Items]
Expiration period	1 year
Maximum | Cash-settled SARs
Accounting Policies [Line Items]
Expiration period	7 years
Other Property and Equipment
Accounting Policies [Line Items]
Depreciation	$ 700,000	$ 1,100,000	$ 900,000
Other Property and Equipment | Minimum
Accounting Policies [Line Items]
Estimated useful lives of other property and equipment	3 years
Other Property and Equipment | Maximum
Accounting Policies [Line Items]
Estimated useful lives of other property and equipment	20 years

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Derivative Instruments and Hedging Activities (Schedule of Gain or Loss on Derivative Contracts) (Details) - USD ($) $ in Thousands	3 Months Ended							12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments	$ (30,700)	$ 21,800	$ 14,000	$ (67,300)	$ 103,900	$ (34,300)	$ (16,600)	$ (62,109)	$ 48,544	$ (18,901)
Total gain (loss) on derivative contracts								(62,109)	48,544	(18,901)
Not Designated as Hedging Instrument
Derivative Instruments, Gain (Loss) [Line Items]
Total gain (loss) on derivative contracts								(62,109)	48,544	(18,901)
Not Designated as Hedging Instrument | Credit Risk Contract
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on fair value adjustments								2,315	0	0
Not Designated as Hedging Instrument | Commodity - Oil
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements								(11,188)	(27,510)	(9,067)
Net gain (loss) on fair value adjustments								(62,125)	72,973	(11,426)
Total gain (loss) on derivative contracts								(73,313)	45,463	(20,493)
Not Designated as Hedging Instrument | Commodity - Natural gas
Derivative Instruments, Gain (Loss) [Line Items]
Net gain (loss) on settlements								7,399	238	594
Net gain (loss) on fair value adjustments								1,490	2,843	998
Total gain (loss) on derivative contracts								$ 8,889	$ 3,081	$ 1,592

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Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Narrative) (Details) MMBoe in Thousands, MBoe in Thousands	3 Months Ended	12 Months Ended
	Dec. 31, 2019 well MBoe MMBoe	Dec. 31, 2019 MBoe	Dec. 31, 2019 MBoe	Dec. 31, 2019 MBoe MMBoe	Dec. 31, 2018 well MBoe	Dec. 31, 2017 well MBoe	Dec. 31, 2019 MMBoe	Dec. 31, 2018 MMBoe	Dec. 31, 2016 MBoe
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve, net (energy)	540,012	540,012	540,012	540,012	238,508	136,974	540,000	238,500	91,580
Proved developed and proved undeveloped reserves, percentage change between periods		126.00%			74.00%	50.00%
Sale of reserves in place			32,456	32,500	0	0
Revisions to previous estimates | MBoe					(11,086)	(4,115)
Permian Basin
Reserve Quantities [Line Items]
Proved developed and undeveloped reserve period increase (decrease)	386,300				124,600	57,900
Number of wells drilled during the period	61				70	49
Number of wells drilled during the period, net	53.7				57.5	38.2
Revisions to previous estimates				(37,216)	2,000
Reclassifications due to changes in development plan | MBoe			(9,800)		(9,100)
Removal of proved undeveloped locations					19	13

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Commitments and Contingencies (Narrative) (Details)	1 Months Ended					12 Months Ended
	Jul. 31, 2019 bbl / d	Jun. 30, 2019 bbl / d	Jan. 31, 2019 bbl / d	Aug. 30, 2018 bbl / d	Mar. 31, 2018	Dec. 31, 2019 contract
Operating Leases And Other Property Plant And Equipment [Line Items]
Agreement period					2 years
Long-term delivery commitment, volume required | bbl / d	5,000	10,000	10,000	15,000
Horizontal Drilling Rig
Operating Leases And Other Property Plant And Equipment [Line Items]
Number of contracts | contract						9

XML

Borrowings (Senior Notes Assumed in Merger) (Details) (Details)				12 Months Ended
	Apr. 15, 2021	Dec. 20, 2019	Oct. 03, 2016	Dec. 31, 2019
8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		8.25%		8.25%
6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument, interest rate, stated (as a percent)		6.25%	6.25%	6.25%
Debt instrument redemption price percent (as a percent)		101.00%
On or After October 1, 2022 | 8.25% Senior Notes due 2025
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			106.188%	100.00%
On or After October 1, 2022 | 6.25% Senior Notes due 2023 | Forecast
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)	100.00%
On or After October 1, 2021, but Before October 1, 2022 | 6.25% Senior Notes due 2023
Debt Instrument [Line Items]
Debt instrument redemption price percent (as a percent)			103.125%

XML

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Future Net Cash Flows Relating to Proved Oil and Gas Reserves, Net Cash Flows [Abstract]
Future cash inflows				$ 20,891,469	$ 11,794,080	$ 5,920,328
Future costs
Production				(6,717,088)	(2,923,959)	(1,692,871)
Development and net abandonment				(3,058,861)	(1,429,787)	(680,948)
Future net inflows before income taxes				11,115,520	7,440,334	3,546,509
Future income taxes				(941,768)	(782,470)	(166,985)
Future net cash flows				10,173,752	6,657,864	3,379,524
10% discount factor				(5,222,726)	(3,716,571)	(1,822,842)
Standardized measure of discounted future net cash flows	$ 2,941,293	$ 1,556,682	$ 1,556,682	$ 4,951,026	$ 2,941,293	$ 1,556,682
Increase (Decrease) in Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves [Roll Forward]
Standardized measure at the beginning of the period	2,941,293	1,556,682	809,832
Sales and transfers, net of production costs	(579,744)	(481,306)	(294,172)
Net change in sales and transfer prices, net of production costs	(387,970)	222,802	176,234
Net change due to purchases of in place reserves	2,975,296	554,697	129,454
Net change due to sales of in place reserves	(303,526)	0	0
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	607,146	1,001,873	635,000
Changes in future development cost	205,398	40,483	(8,148)
Previously estimated development costs incurred	134,037	91,900	45,131
Revisions of quantity estimates	(420,488)	(167,096)	(79,325)
Accretion of discount	314,921	157,676	80,983
Net change in income taxes	(210,641)	(187,841)	(20,073)
Changes in production rates, timing and other	(324,696)	151,423	81,766
Aggregate change	2,009,733	1,384,611	746,850
Standardized measure at the end of period	$ 4,951,026	$ 2,941,293	$ 1,556,682

XML

Share-Based Compensation (RSU Equity Awards (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
RSU equity awards
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested at the beginning of the period (in shares)	2,103,000	1,790,000	1,448,000
Granted (in shares)	1,881,000	872,000	1,173,000
Vested (in shares)	(1,062,000)	(506,000)	(797,000)
Forfeited (in shares)	(227,000)	(53,000)	(34,000)
Unvested at the end of the period (in shares)	2,695,000	2,103,000	1,790,000
Weighted Average Grant-Date Fair Value per Share
Unvested at the beginning of the period, Grant Date Fair Value per Share (usd per share)	$ 13.24	$ 11.54	$ 10.81
Granted, grant date fair value per share (usd per share)	8.60	13.89	12.25
Vested, grant date fair value per share (usd per share)	12.35	9.56	11.35
Forfeited, grant date fair value per share (usd per share)	10.59	11.43	9.57
Unvested at the end of the period, grant date fair value per share (usd per share)	$ 10.57	$ 13.24	$ 11.54
Share-based compensation arrangement vesting rights, percentage			142.00%
Fair value of shares vested	$ 7.3	$ 6.3	$ 9.0
RSU equity awards | Vesting range 0 to 200%
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested at the beginning of the period (in shares)	208,000	89,000
Unvested at the end of the period (in shares)	399,425	208,000	89,000
RSU equity awards | Vesting Minimum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	0.00%
RSU equity awards | Vesting Maximum
Weighted Average Grant-Date Fair Value per Share
Share-based compensation arrangement vesting rights, percentage	200.00%
Performance-based RSU
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Outstanding [Roll Forward]
Unvested at the beginning of the period (in shares)		73,000
Unvested at the end of the period (in shares)			73,000
Weighted Average Grant-Date Fair Value per Share
Fair value of shares vested	$ 4.3	$ 3.5	$ 2.6

XML

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Supplemental Information on Oil and Natural Gas Properties (Unaudited)

Supplemental Information on Oil and Natural Gas Operations (Unaudited)

Estimated Reserves

The estimated proved reserves obtained as a result of the Carrizo Acquisition were prepared by Ryder Scott Company, L.P. (“Ryder Scott”), the independent third party reserve engineers historically retained by Carrizo. All other estimated proved reserves for each respective year were prepared by DeGolyer and MacNaughton (“D&M”), Callon’s independent third party reserve engineers (together with Ryder Scott, the “Reserve Engineering Firms”). 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 Reserve Engineering Firms 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.

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	2019		2018		2017
Oil (MBbls)
Beginning of period	180,097		107,072		71,145
Purchase of reserves in place	183,382		30,756		8,388
Sales of reserves in place	(17,980	)	—		—
Extensions and discoveries	45,663		67,763		39,267
Revisions to previous estimates	(33,136	)	(16,051	)	(5,171	)
Production	(11,665	)	(9,443	)	(6,557	)
End of period	346,361		180,097		107,072
Natural Gas (MMcf)
Beginning of period	350,466		179,410		122,611
Purchase of reserves in place	455,158		53,563		12,711
Sale of reserves in place	(86,856	)	—		—
Extensions and discoveries	82,566		103,149		48,648
Revisions to previous estimates	(24,482	)	29,791		6,336
Production	(19,718	)	(15,447	)	(10,896	)
End of period	757,134		350,466		179,410
NGLs (MBbls)
Beginning of period	—		—		—
Purchase of reserves in place	67,597		—		—
Production	(135	)	—		—
End of period	67,462		—		—
Total (MBoe)
Beginning of period	238,508		136,974		91,580
Purchase of reserves in place	326,838		39,683		10,507
Sale of reserves in place	(32,456	)	—		—
Extensions and discoveries	59,424		84,955		47,375
Revisions to previous estimates	(37,216	)	(11,086	)	(4,115	)
Production	(15,086	)	(12,018	)	(8,373	)
End of period	540,012		238,508		136,974

	Years Ended December 31,
Proved developed reserves:	2019	2018	2017
Oil (MBbls)
Beginning of period	92,202	51,920	32,920
End of period	152,687	92,202	51,920
Natural gas (MMcf)
Beginning of period	218,417	104,389	61,871
End of period	320,676	218,417	104,389
NGLs (MBbls)
Beginning of period	—	—	—
End of period	24,844	—	—
Total proved developed reserves (MBoe)
Beginning of period	128,605	69,318	43,232
End of period	230,977	128,605	69,318
Proved undeveloped reserves
Oil (MBbls)
Beginning of period	87,895	55,152	38,225
End of period	193,674	87,895	55,152
Natural gas (MMcf)
Beginning of period	132,049	75,021	60,740
End of period	436,458	132,049	75,021
NGLs (MBbls)
Beginning of period	—	—	—
End of period	42,618	—	—
Total proved undeveloped reserves (MBoe)
Beginning of period	109,903	67,656	48,348
End of period	309,035	109,903	67,656
Total proved reserves
Oil (MBbls)
Beginning of period	180,097	107,072	71,145
End of period	346,361	180,097	107,072
Natural gas (MMcf)
Beginning of period	350,466	179,410	122,611
End of period	757,134	350,466	179,410
NGLs (MBbls)
Beginning of period	—	—	—
End of period	67,462	—	—
Total proved reserves (MBoe)
Beginning of period	238,508	136,974	91,580
End of period	540,012	238,508	136,974

Total Proved Reserves

The Company ended 2019 with estimated proved reserves of 540.0 MMBoe, representing a 126% increase over 2018 year-end estimated proved reserves of 238.5 MMBoe. The Company added 386.3 MMBoe primarily from the Carrizo Acquisition completed in the fourth quarter of 2019 and development efforts in the Permian Basin, where it drilled a total of 61 gross (53.7 net) wells. This increase was offset by 2019 production, sales of reserves of 32.5 MMBoe, which are primarily related to the Ranger Divestiture, and negative revisions of previous estimates of 37.2 MMBoe. The negative revisions include 9.8 MMBoe from the reclassifications of PUDs within our optimized our development plans that were moved outside of the five-year development window. The primary driver of these changes in our previous development plan was the Carrizo Acquisition which allowed the Company to reallocate capital across the combined portfolio in an effort to increase capital efficiency and resulting cash flow generation. The remaining negative revisions were primarily from the observed impact of well spacing tests on producing wells and the related impact on reserve estimates as the Company advanced larger scale development concepts across its multi-zone inventory as well as the adverse effect of pricing and other economic factors.

The Company ended 2018 with estimated net proved reserves of 238.5 MMBoe, representing a 74% increase over 2017 year-end estimated net proved reserves of 137.0 MMBoe. The Company added 124.6 MMBoe primarily from the Delaware Asset Acquisition completed third quarter of 2018 and development efforts in the Permian Basin, where it drilled a total of 70 gross (57.5 net) wells. This increase was offset by 2018 production, negative revisions of previous estimates of 2.0 MMBoe primarily related to technical revisions of proved undeveloped reserves, and reclassifications of proved undeveloped reserves of 9.1 MMBoe from 19 PUD locations primarily due to

acreage trades and changes in our development plan, including larger pad development concepts and co-development of zones. These changes resulted in the anticipated drilling of PUD locations being moved beyond five years from initial booking.

The Company ended 2017 with estimated net proved reserves of 137.0 MMBoe, representing a 50% increase over 2016 year-end estimated net proved reserves of 91.6 MMBoe. The Company added 57.9 MMBoe 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, revisions of previous estimates, and reclassifications of PUD locations from our development and drilling plan. The Company reclassified 13 PUD 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.

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,
	2019			2018
Oil and natural gas properties:	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties	9,189,606			5,989,533
Accumulated depreciation, depletion, amortization and impairment	(2,520,488		)	(2,270,675		)
Total oil and natural gas properties capitalized		$6,669,118			$3,718,858

Costs Incurred

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:

	Years Ended December 31,
	2019		2018		2017
Acquisition costs:	(In thousands)
Evaluated properties		$49,572		$347,305		$156,340
Unevaluated properties	107,347		466,816		499,295
Development costs	189,259		259,410		148,254
Exploration costs	309,013		323,458		239,453
Total costs incurred		$655,191		$1,396,989		$1,043,342

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, 2019. 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,
	2019		2018		2017
Oil ($/Bbl) (1)		$53.90		$58.40		$49.48
Natural gas ($/Mcf) (2)		$1.55		$3.64		$3.47
NGLs ($/Bbl)		$15.58		$—		$—

(1) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

(2) Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.

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,
	2019			2018			2017
	(In thousands)
Future cash inflows		$20,891,469			$11,794,080			$5,920,328
Future costs
Production	(6,717,088		)	(2,923,959		)	(1,692,871		)
Development and net abandonment	(3,058,861		)	(1,429,787		)	(680,948		)
Future net inflows before income taxes	11,115,520			7,440,334			3,546,509
Future income taxes	(941,768		)	(782,470		)	(166,985		)
Future net cash flows	10,173,752			6,657,864			3,379,524
10% discount factor	(5,222,726		)	(3,716,571		)	(1,822,842		)
Standardized measure of discounted future net cash flows		$4,951,026			$2,941,293			$1,556,682

໿

	Changes in Standardized Measure
	For the Year Ended December 31,
	2019			2018			2017
	(In thousands)
Standardized measure at the beginning of the period		$2,941,293			$1,556,682			$809,832
Sales and transfers, net of production costs	(579,744		)	(481,306		)	(294,172		)
Net change in sales and transfer prices, net of production costs	(387,970		)	222,802			176,234
Net change due to purchases of in place reserves	2,975,296			554,697			129,454
Net change due to sales of in place reserves	(303,526		)	—			—
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	607,146			1,001,873			635,000
Changes in future development cost	205,398			40,483			(8,148		)
Previously estimated development costs incurred	134,037			91,900			45,131
Revisions of quantity estimates	(420,488		)	(167,096		)	(79,325		)
Accretion of discount	314,921			157,676			80,983
Net change in income taxes	(210,641		)	(187,841		)	(20,073		)
Changes in production rates, timing and other	(324,696		)	151,423			81,766
Aggregate change	2,009,733			1,384,611			746,850
Standardized measure at the end of period		$4,951,026			$2,941,293			$1,556,682

XML

Accounts Receivable, Net

12 Months Ended

Dec. 31, 2019

Receivables [Abstract]

Accounts Receivable, Net

Accounts Receivable, Net

	As of December 31,
	2019			2018
	(In thousands)
Oil and natural gas receivables		$165,275			$87,062
Joint interest receivables	42,493			42,373
Other receivables	3,231			3,150
Total	210,999			132,585
Allowance for doubtful accounts	(1,536		)	(865		)
Total accounts receivable, net		$209,463			$131,720

XML

Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Tables)

12 Months Ended

Dec. 31, 2019

Oil and Gas Exploration and Production Industries Disclosures [Abstract]

Schedule of Proved Developed and Undeveloped Oil and Gas Reserve Quantities

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	2019		2018		2017
Oil (MBbls)
Beginning of period	180,097		107,072		71,145
Purchase of reserves in place	183,382		30,756		8,388
Sales of reserves in place	(17,980	)	—		—
Extensions and discoveries	45,663		67,763		39,267
Revisions to previous estimates	(33,136	)	(16,051	)	(5,171	)
Production	(11,665	)	(9,443	)	(6,557	)
End of period	346,361		180,097		107,072
Natural Gas (MMcf)
Beginning of period	350,466		179,410		122,611
Purchase of reserves in place	455,158		53,563		12,711
Sale of reserves in place	(86,856	)	—		—
Extensions and discoveries	82,566		103,149		48,648
Revisions to previous estimates	(24,482	)	29,791		6,336
Production	(19,718	)	(15,447	)	(10,896	)
End of period	757,134		350,466		179,410
NGLs (MBbls)
Beginning of period	—		—		—
Purchase of reserves in place	67,597		—		—
Production	(135	)	—		—
End of period	67,462		—		—
Total (MBoe)
Beginning of period	238,508		136,974		91,580
Purchase of reserves in place	326,838		39,683		10,507
Sale of reserves in place	(32,456	)	—		—
Extensions and discoveries	59,424		84,955		47,375
Revisions to previous estimates	(37,216	)	(11,086	)	(4,115	)
Production	(15,086	)	(12,018	)	(8,373	)
End of period	540,012		238,508		136,974

	Years Ended December 31,
Proved developed reserves:	2019	2018	2017
Oil (MBbls)
Beginning of period	92,202	51,920	32,920
End of period	152,687	92,202	51,920
Natural gas (MMcf)
Beginning of period	218,417	104,389	61,871
End of period	320,676	218,417	104,389
NGLs (MBbls)
Beginning of period	—	—	—
End of period	24,844	—	—
Total proved developed reserves (MBoe)
Beginning of period	128,605	69,318	43,232
End of period	230,977	128,605	69,318
Proved undeveloped reserves
Oil (MBbls)
Beginning of period	87,895	55,152	38,225
End of period	193,674	87,895	55,152
Natural gas (MMcf)
Beginning of period	132,049	75,021	60,740
End of period	436,458	132,049	75,021
NGLs (MBbls)
Beginning of period	—	—	—
End of period	42,618	—	—
Total proved undeveloped reserves (MBoe)
Beginning of period	109,903	67,656	48,348
End of period	309,035	109,903	67,656
Total proved reserves
Oil (MBbls)
Beginning of period	180,097	107,072	71,145
End of period	346,361	180,097	107,072
Natural gas (MMcf)
Beginning of period	350,466	179,410	122,611
End of period	757,134	350,466	179,410
NGLs (MBbls)
Beginning of period	—	—	—
End of period	67,462	—	—
Total proved reserves (MBoe)
Beginning of period	238,508	136,974	91,580
End of period	540,012	238,508	136,974

Capitalized Costs Relating to Oil and Natural Gas Activities

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,
	2019			2018
Oil and natural gas properties:	(In thousands)
Evaluated properties		$7,203,482			$4,585,020
Unevaluated properties	1,986,124			1,404,513
Total oil and natural gas properties	9,189,606			5,989,533
Accumulated depreciation, depletion, amortization and impairment	(2,520,488		)	(2,270,675		)
Total oil and natural gas properties capitalized		$6,669,118			$3,718,858

Cost Incurred in Oil and Gas Property Acquisition, Exploration, and Development Activities

Costs incurred in oil and natural gas property acquisitions, exploration and development activities are as follows:

	Years Ended December 31,
	2019		2018		2017
Acquisition costs:	(In thousands)
Evaluated properties		$49,572		$347,305		$156,340
Unevaluated properties	107,347		466,816		499,295
Development costs	189,259		259,410		148,254
Exploration costs	309,013		323,458		239,453
Total costs incurred		$655,191		$1,396,989		$1,043,342

Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure

໿

	Years Ended December 31,
	2019		2018		2017
Oil ($/Bbl) (1)		$53.90		$58.40		$49.48
Natural gas ($/Mcf) (2)		$1.55		$3.64		$3.47
NGLs ($/Bbl)		$15.58		$—		$—

(1) Includes adjustments to reflect all wellhead deductions and premiums on a property-by-property basis, including transportation costs, location differentials and crude quality.

(2)

Includes a high Btu content of separator natural gas and adjustments to reflect the Btu content, transportation charges and other fees specific to the individual properties.

Standardized Measure of Discounted Future Cash Flows Relating to Proved Reserves Disclosure

	Standardized Measure
	For the Year Ended December 31,
	2019			2018			2017
	(In thousands)
Future cash inflows		$20,891,469			$11,794,080			$5,920,328
Future costs
Production	(6,717,088		)	(2,923,959		)	(1,692,871		)
Development and net abandonment	(3,058,861		)	(1,429,787		)	(680,948		)
Future net inflows before income taxes	11,115,520			7,440,334			3,546,509
Future income taxes	(941,768		)	(782,470		)	(166,985		)
Future net cash flows	10,173,752			6,657,864			3,379,524
10% discount factor	(5,222,726		)	(3,716,571		)	(1,822,842		)
Standardized measure of discounted future net cash flows		$4,951,026			$2,941,293			$1,556,682

໿

	Changes in Standardized Measure
	For the Year Ended December 31,
	2019			2018			2017
	(In thousands)
Standardized measure at the beginning of the period		$2,941,293			$1,556,682			$809,832
Sales and transfers, net of production costs	(579,744		)	(481,306		)	(294,172		)
Net change in sales and transfer prices, net of production costs	(387,970		)	222,802			176,234
Net change due to purchases of in place reserves	2,975,296			554,697			129,454
Net change due to sales of in place reserves	(303,526		)	—			—
Extensions, discoveries, and improved recovery, net of future production and development costs incurred	607,146			1,001,873			635,000
Changes in future development cost	205,398			40,483			(8,148		)
Previously estimated development costs incurred	134,037			91,900			45,131
Revisions of quantity estimates	(420,488		)	(167,096		)	(79,325		)
Accretion of discount	314,921			157,676			80,983
Net change in income taxes	(210,641		)	(187,841		)	(20,073		)
Changes in production rates, timing and other	(324,696		)	151,423			81,766
Aggregate change	2,009,733			1,384,611			746,850
Standardized measure at the end of period		$4,951,026			$2,941,293			$1,556,682

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Summary of Significant Accounting Policies (Supplemental Cash Flow Information) (Details) - USD ($)	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Supplemental cash flow information:
Interest paid, net of capitalized amounts	$ 0	$ 0	$ 0
Income taxes paid	0	0	0
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	3,414,000	0	0
Investing cash flows from operating leases	32,529,000	0	0
Non-cash investing and financing activities:
Change in accrued capital expenditures	(31,475,000)	(52,757,000)	(39,532,000)
Change in asset retirement costs	13,559,000	8,730,000	(607,000)
Contingent consideration arrangement	8,512,000	0	0
ROU assets obtained in exchange for lease liabilities:
Operating leases	66,914,000
Financing leases	2,197,000
Federal
Supplemental cash flow information:
Income taxes paid	$ 0	$ 0	$ 0

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Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Oil and Gas Net Production, Average Sales Price and Average Production Costs Disclosure) (Details)	12 Months Ended
	Dec. 31, 2019 $ / bbl $ / Boe	Dec. 31, 2018 $ / bbl $ / Boe	Dec. 31, 2017 $ / bbl $ / Boe
Commodity - Oil
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials | $ / Boe	53.90	58.40	49.48
Commodity - Natural gas
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials	1.55	3.64	3.47
Natural gas liquids
Average Sales Price and Production Costs Per Unit of Production [Line Items] (Deprecated 2019-01-31)
Average 12-month price, net of differentials	15.58	0	0

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Fair Value Measurements (Fair Value of Assets and Liabilities Measured on Recurring Basis) (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Level 1
Assets
Fair value of derivatives	$ 0	$ 0
Contingent consideration arrangements	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Total net assets (liabilities)	0	0
Level 2
Assets
Fair value of derivatives	9,338	65,114
Contingent consideration arrangements	25,934
Liabilities
Fair value of derivatives	(34,132)	(17,920)
Contingent consideration arrangements	(69,760)
Total net assets (liabilities)	(68,620)	47,194
Level 3
Assets
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Liabilities
Fair value of derivatives	0	0
Contingent consideration arrangements	0
Total net assets (liabilities)	$ 0	$ 0

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Derivative Instruments and Hedging Activities (Schedule of Derivative Instruments in Statement of Financial Position, Fair Value) (Details) - Not Designated as Hedging Instrument - USD ($)	Dec. 31, 2019	Dec. 31, 2018
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	$ 43,567,000	$ 78,091,000
Effects of Netting	(17,511,000)	(12,977,000)
As Presented with Effects of Netting	26,056,000	65,114,000
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	16,718,000
Effects of Netting	0
As Presented with Effects of Netting	16,718,000
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	26,849,000
Effects of Netting	(17,511,000)
As Presented with Effects of Netting	9,338,000
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	9,216,000
Effects of Netting	0
As Presented with Effects of Netting	9,216,000
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	9,216,000
Effects of Netting	0
As Presented with Effects of Netting	9,216,000
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	0
Effects of Netting	0
As Presented with Effects of Netting	0
Fair value of derivatives - Current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(88,708,000)	(23,457,000)
Effects of Netting	17,511,000	12,977,000
As Presented with Effects of Netting	(71,197,000)	(10,480,000)
Fair value of derivatives - Current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(50,000,000)
Effects of Netting	0
As Presented with Effects of Netting	(50,000,000)
Fair value of derivatives - Current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(38,708,000)
Effects of Netting	17,511,000
As Presented with Effects of Netting	(21,197,000)
Fair value of derivatives - Non-current
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(32,695,000)	(7,440,000)
Effects of Netting	0	0
As Presented with Effects of Netting	(32,695,000)	$ (7,440,000)
Fair value of derivatives - Non-current | Contingent consideration arrangements
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(19,760,000)
Effects of Netting	0
As Presented with Effects of Netting	(19,760,000)
Fair value of derivatives - Non-current | Commodity derivative instruments
Offsetting Assets and Liabilities [Line Items]
Presented without Effects of Netting	(12,935,000)
Effects of Netting	0
As Presented with Effects of Netting	$ (12,935,000)

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Supplemental Information on Oil and Natural Gas Properties (Unaudited) (Proved Developed and Undeveloped Oil and Gas Reserve Quantities) (Details) MMcf in Thousands, MBoe in Thousands, MBbls in Thousands, MMBoe in Millions	12 Months Ended
	Dec. 31, 2019 MMcf	Dec. 31, 2019 MBbls	Dec. 31, 2019 MBoe	Dec. 31, 2019 MMBoe	Dec. 31, 2018 MMcf	Dec. 31, 2018 MBbls	Dec. 31, 2018 MBoe	Dec. 31, 2017 MBoe MMcf MBbls
Proved developed and undeveloped reserves (Energy):
Beginning of period			238,508	238.5			136,974	91,580
Purchase of reserves in place | MBoe			326,838				39,683	10,507
Sale of reserves in place			(32,456)	(32.5)			0	0
Extensions and discoveries | MBoe			59,424				84,955	47,375
Revisions to previous estimates | MBoe							(11,086)	(4,115)
Production | MBoe			(15,086)				(12,018)	(8,373)
End of period			540,012	540.0			238,508	136,974
Proved undeveloped reserves:
Beginning of period, MBOE proved developed | MBoe			128,605				69,318	43,232
End of period, MBOE proved developed | MBoe			230,977				128,605	69,318
Beginning of periodic, MBOE proved developed | MBoe			109,903				67,656	48,348
End of period, MBOE proved developed | MBoe			309,035				109,903	67,656
Commodity - Oil
Proved developed and undeveloped reserves:
Beginning of period | MBbls		180,097				107,072		71,145
Purchase of reserves in place | MBbls		183,382				30,756		8,388
Sales of reserves in place | MBbls		(17,980)				0		0
Extensions and discoveries | MBbls		45,663				67,763		39,267
Revisions to previous estimates | MBbls		(33,136)				(16,051)		(5,171)
Production | MBbls		(11,665)				(9,443)		(6,557)
End of period | MBbls		346,361				180,097		107,072
Proved undeveloped reserves:
Beginning of period, proved developed | MBbls		92,202				51,920		32,920
End of period, proved developed | MBbls		152,687				92,202		51,920
Beginning of period, proved undeveloped | MBbls		87,895				55,152		38,225
End of period, proved undeveloped | MBbls		193,674				87,895		55,152
Proved Developed and Undeveloped Reserves (Volume) | MBbls		180,097				107,072		71,145
Proved Developed and Undeveloped Reserves (Volume) | MBbls		346,361				180,097		107,072
Commodity - Natural gas
Proved developed and undeveloped reserves:
Beginning of period	350,466				179,410			122,611
Purchase of reserves in place	455,158				53,563			12,711
Sales of reserves in place	(86,856)				0			0
Extensions and discoveries	82,566				103,149			48,648
Revisions to previous estimates	(24,482)				29,791			6,336
Production	(19,718)				(15,447)			(10,896)
End of period	757,134				350,466			179,410
Proved undeveloped reserves:
Beginning of period, proved developed	218,417				104,389			61,871
End of period, proved developed	320,676				218,417			104,389
Beginning of period, proved undeveloped	132,049				75,021			60,740
End of period, proved undeveloped	436,458				132,049			75,021
Proved Developed and Undeveloped Reserves (Volume)	350,466				179,410			122,611
Proved Developed and Undeveloped Reserves (Volume)	757,134				350,466			179,410
Natural gas liquids
Proved developed and undeveloped reserves:
Beginning of period	0				0			0
Purchase of reserves in place	67,597				0			0
Production	(135)				0			0
End of period	67,462				0			0
Proved undeveloped reserves:
Beginning of period, proved developed	0				0			0
End of period, proved developed	24,844				0			0
Beginning of period, proved undeveloped	0				0			0
End of period, proved undeveloped	42,618				0			0
Proved Developed and Undeveloped Reserves (Volume) | MBbls		0				0		0
Proved Developed and Undeveloped Reserves (Volume) | MBbls		67,462				0		0

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Accounts Payable and Accrued Liabilities (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Payables and Accruals [Abstract]
Accounts payable	$ 238,758	$ 83,412
Revenues payable	145,816	94,114
Accrued capital expenditures	61,950	83,658
Accrued interest	36,295	24,665
Accrued severance	28,803	0
Total accounts payable and accrued liabilities	$ 511,622	$ 285,849

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Borrowings (6.125% Senior Notes) (Details) - USD ($)	May 19, 2017	Oct. 03, 2016	Dec. 31, 2019	Dec. 31, 2017
Unsecured debt | Callon Petroleum Operating Company
Debt Instrument, Redemption [Line Items]
Ownership percentage by parent			100.00%
6.125% Senior Notes due 2024
Debt Instrument, Redemption [Line Items]
Debt instrument, interest rate, stated (as a percent)	6.125%	6.125%	6.125%	6.125%
Debt instrument aggregate principal amount	$ 200,000,000.0	$ 400,000,000.0
Debt instrument redemption price percent (as a percent)	104.125%
Proceeds from issuance of debt	$ 206,100,000
6.125% Senior Notes due 2024 | Change Of Control
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		101.00%
6.125% Senior Notes due 2024 | On or After October 1, 2019, but Before October 1, 2020
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		104.594%
6.125% Senior Notes due 2024 | On or After October 1, 2022
Debt Instrument, Redemption [Line Items]
Debt instrument redemption price percent (as a percent)		100.00%

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Earnings Per Share (Details) - USD ($) $ / shares in Units, shares in Thousands, $ in Thousands	3 Months Ended								12 Months Ended
	Dec. 31, 2019	Sep. 30, 2019	Jun. 30, 2019	Mar. 31, 2019	Dec. 31, 2018	Sep. 30, 2018	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Earnings Per Share, Basic and Diluted
Net income	$ (23,543)	$ 55,834	$ 55,180	$ (19,543)	$ 156,194	$ 37,931	$ 50,474	$ 55,761	$ 67,928	$ 300,360	$ 120,424
Preferred stock dividends									(3,997)	(7,295)	(7,295)
Loss on redemption of preferred stock		(8,300)							(8,304)	0	0
Income Available to Common Stockholders	$ (23,543)	$ 47,180	$ 53,357	$ (21,367)	$ 154,370	$ 36,108	$ 48,650	$ 53,937	$ 55,627	$ 293,065	$ 113,129
Weighted average shares outstanding (in shares)									233,140	216,941	201,526
Dilutive impact of restricted stock (in shares)									410	655	576
Weighted average shares outstanding for diluted income per share (in shares)									233,550	217,596	202,102
Basic income per share (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Diluted income (loss) per share (in dollars per share)	$ (0.09)	$ 0.21	$ 0.23	$ (0.09)	$ 0.68	$ 0.16	$ 0.23	$ 0.27	$ 0.24	$ 1.35	$ 0.56
Restricted stock
Earnings Per Share, Basic and Diluted
Restricted stock									998	89	16

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Description of Business

12 Months Ended

Dec. 31, 2019

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Description of Business

Description of Business

Callon Petroleum Company is an independent oil and natural gas company established in 1950. The Company was incorporated under the laws of the state of Delaware in 1994 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. As used herein, the “Company,” “Callon,” “we,” “us,” and “our” refer to Callon Petroleum Company and its predecessors and subsidiaries unless the context requires otherwise.

Callon is an independent oil and natural gas company focused on the acquisition, exploration and development of high-quality assets in the leading oil plays of South and West Texas. The Company’s activities are primarily focused on horizontal development in the Midland and Delaware Basins, both of which are part of the larger Permian Basin in West Texas. In 2019, through its acquisition of Carrizo Oil & Gas, Inc. (“Carrizo”), the Company doubled its core acreage position in the Delaware Basin and entered the Eagle Ford Shale. The Company’s primary operations in the Permian Basin reflect a high-return, oil-weighted drilling inventory with multiple prospective horizontal development intervals and are complemented by a well-established and repeatable free cash flow generating business in the Eagle Ford Shale.

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Acquisitions and Divestitures (Fair Value of Net Assets Acquired ) (Details) - USD ($) $ in Thousands	Aug. 31, 2018	Feb. 13, 2017
Cimarex Energy Company
Assets:
Total oil and natural gas properties	$ 540,089
Total assets acquired	540,089
Liabilities:
Asset retirement obligation	(570)
Total liabilities assumed	(570)
Net Assets Acquired	539,519
Cimarex Energy Company | Evaluated properties
Assets:
Total oil and natural gas properties	253,089
Cimarex Energy Company | Unevaluated properties
Assets:
Total oil and natural gas properties	$ 287,000
Delaware Basin
Assets:
Total oil and natural gas properties		$ 646,727
Total assets acquired		646,727
Liabilities:
Asset retirement obligation		(168)
Total liabilities assumed		(168)
Net Assets Acquired		646,559
Delaware Basin | Evaluated properties
Assets:
Total oil and natural gas properties		137,368
Delaware Basin | Unevaluated properties
Assets:
Total oil and natural gas properties		$ 509,359

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Consolidated Statements of Operations - USD ($) shares in Thousands, $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Operating Revenues:
Total operating revenues	$ 671,572	$ 587,624	$ 366,474
Operating Expenses:
Lease operating	91,827	69,180	49,907
Production taxes	42,651	35,755	22,396
Depreciation, depletion and amortization	240,642	182,783	116,391
General and administrative	45,331	35,293	27,067
Merger and integration expenses	74,363	0	0
Settled share-based awards	3,024	0	6,351
Other operating expense	1,076	5,083	2,916
Total operating expenses	498,914	328,094	225,028
Income From Operations	172,658	259,530	141,446
Other (Income) Expenses:
Interest expense, net of capitalized amounts	2,907	2,500	2,159
(Gain) loss on derivative contracts	62,109	(48,544)	18,901
Loss on extinguishment of debt	4,881	0	0
Other income	(468)	(2,896)	(1,311)
Total other (income) expense	69,429	(48,940)	19,749
Income Before Income Taxes	103,229	308,470	121,697
Income tax expense	35,301	8,110	1,273
Net Income	67,928	300,360	120,424
Preferred stock dividends	(3,997)	(7,295)	(7,295)
Loss on redemption of preferred stock	(8,304)	0	0
Income Available to Common Stockholders	$ 55,627	$ 293,065	$ 113,129
Income Available to Common Stockholders Per Common Share:
Basic (in dollars per share)	$ 0.24	$ 1.35	$ 0.56
Diluted (in dollars per share)	$ 0.24	$ 1.35	$ 0.56
Weighted Average Common Shares Outstanding:
Basic (in shares)	233,140	216,941	201,526
Diluted (in shares)	233,550	217,596	202,102
Oil
Operating Revenues:
Total operating revenues	$ 633,107	$ 530,898	$ 322,374
Natural gas
Operating Revenues:
Total operating revenues	36,390	56,726	44,100
Natural gas liquids
Operating Revenues:
Total operating revenues	$ 2,075	$ 0	$ 0

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Share-Based Compensation (Shares Vested and Did Not Vest) (Details) - RSU equity awards - shares	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier	100.00%	142.00%
Target (in shares)	88,790	83,002	258,406
Vested at end of performance period (in shares)	88,790	117,862	441,232
Did not vest at end of performance period (in shares)	0	0	0
Minimum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			142.00%
Maximum
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Vesting Multiplier			200.00%

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Income Taxes (Narrative) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Business Acquisition [Line Items]
Operating loss carryforwards	$ 527,200
Deferred income tax valuation allowance	180,777	$ 170,302
Non-deductible merger expenses	5,537	0	$ 0
Statutory depletion carryforward	5,381	$ 0	$ 0
Statutory depletion carryforward	24,900
Operating loss carryforwards, subject to expiration	496,500
Post 2017, net operating loss	30,700
Carrizo
Business Acquisition [Line Items]
Operating loss carryforwards	288,200
Deferred income tax valuation allowance	$ 159,300

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Leases (Assets and Liabilities) (Details) $ in Thousands	Dec. 31, 2019 USD ($)
Operating Leases [Abstract]
Operating lease ROU assets	$ 63,908
Current operating lease liabilities	42,858
Long-term operating lease liabilities	37,088
Total operating lease liabilities	79,946
Finance Leases [Abstract]
Other property and equipment	2,197
Accumulated depreciation	(82)
Other property and equipment, net	2,115
Current financing lease liabilities	1,334
Long-term financing lease liabilities	807
Total financing lease liabilities	$ 2,141

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Share-Based Compensation (Schedule of Cash-Settleable RSUs Outstanding) (Details) - Cash-settleable RSU awards shares in Thousands	12 Months Ended
	Dec. 31, 2019 shares
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	689
Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24
Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	1,355
Vesting in 2020
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	292
Vesting in 2020 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2020 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	586
Vesting in 2021
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	373
Vesting in 2021 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2021 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	745
Vesting in 2022
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	0
Vesting in 2022 | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Vesting in 2022 | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	0
Other
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs base units outstanding	24
Other | Minimum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24
Other | Maximum
Defined Benefit Plan Disclosure [Line Items]
Cash-settleable RSUs potential units vesting	24

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Income Taxes (Expenses) (Details) - USD ($) $ in Thousands	12 Months Ended
	Dec. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Current Income Tax Expense (Benefit), Continuing Operations [Abstract]
Current Federal Tax Expense (Benefit)	$ 0	$ 0	$ (48)
Current State and Local Tax Expense (Benefit)	220	0	0
Current Income Tax Expense (Benefit)	220	0	(48)
Deferred Income Tax Expense (Benefit), Continuing Operations [Abstract]
Deferred Federal Income Tax Expense (Benefit)	33,584	3,594	(45)
Deferred State and Local Income Tax Expense (Benefit)	1,497	4,516	1,366
Deferred Income Tax Expense (Benefit)	35,081	8,110	1,321
Income tax expense	$ 35,301	$ 8,110	$ 1,273

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Accounts Receivable, Net (Details) - USD ($) $ in Thousands	Dec. 31, 2019	Dec. 31, 2018
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 210,999	$ 132,585
Allowance for doubtful accounts	(1,536)	(865)
Total accounts receivable, net	209,463	131,720
Joint interest receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	42,493	42,373
Other receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	3,231	3,150
Oil and natural gas receivables
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, gross	$ 165,275	$ 87,062

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Stockholders' Equity

12 Months Ended

Dec. 31, 2019

Equity [Abstract]

Stockholders' Equity

Stockholders’ Equity

Increase in Authorized Common Shares

As a result of the Carrizo Acquisition, the shareholders approved an amendment to the Company’s Certificate of Incorporation to increase the number of authorized shares of common stock from 300,000,000 to 525,000,000.

10% Series A Cumulative Preferred Stock (“Preferred Stock”)

Holders of the Company’s Preferred Stock were entitled to receive, when, as and if declared by the Company’s 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). Dividends were payable quarterly in arrears on the last day of each March, June, September and December when, as and if declared by the Board of Directors. Preferred Stock dividends were $4.0 million, $7.3 million and $7.3 million for years ended December 31, 2019, 2018 and 2017, respectively.

On June 18, 2019, the Company announced it had given notice for the redemption (the “Redemption”) of all outstanding shares of the Preferred Stock. On July 18, 2019 (the “Redemption Date”), the Preferred Stock were redeemed at a redemption price equal to $50.00 per share, plus an amount equal to all accrued and unpaid dividends in an amount equal to $0.24 per share, for a total redemption price of $50.24 per share or $73.0 million (the “Redemption Price”). The Company recognized an $8.3 million loss on the redemption due to the excess of the $73.0 million redemption price over the $64.7 million redemption date carrying value of the Preferred Stock.

After the Redemption Date, the Preferred Stock were no longer deemed outstanding, dividends on the Preferred Stock ceased to accrue, and all rights of the holders with respect to such Preferred Stock were terminated, except the right of the holders to receive the Redemption Price, without interest.

Common Stock Offerings

On May 30, 2018, the Company completed an underwritten public offering of 25.3 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and offering costs) of approximately $288.0 million. The Company used proceeds from the offering to partially fund the Delaware Asset Acquisition completed in the third quarter of 2018. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Delaware Asset Acquisition.

On December 19, 2016, the Company completed an underwritten public offering of 40.0 million shares of its common stock for total estimated net proceeds (after the underwriter’s discounts and estimated offering expenses) of approximately $634.9 million. Proceeds from the offering were used to partially fund the Ameredev Acquisition. See “Note 4 - Acquisitions and Divestitures” for further discussion of the Ameredev Acquisition.

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Borrowings

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Borrowings

Borrowings

The Company’s borrowings consisted of the following:

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	As of December 31,
	2019			2018
	(In thousands)
Senior Secured Revolving Credit Facility due 2024		$1,285,000			$200,000
6.25% Senior Notes due 2023 (1)	650,000			—
6.125% Senior Notes due 2024	600,000			600,000
8.25% Senior Notes due 2025 (1)	250,000			—
6.375% Senior Notes due 2026	400,000			400,000
Total principal outstanding	3,185,000			1,200,000
Unamortized premium for 6.125% Senior Notes	5,344			6,469
Unamortized premium for 6.25% Senior Notes	4,838			—
Unamortized premium for 8.25% Senior Notes	5,286			—
Unamortized deferred financing costs for Senior Notes	(14,359		)	(16,996		)
Total carrying value of borrowings (2)		$3,186,109			$1,189,473

(1) As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25% Senior Notes and 8.25% Senior Notes.

(2) Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $6.1 million as of December 31, 2019 and 2018, respectively.

Senior Secured Revolving Credit Facility

On May 25, 2017, the Company entered into the Sixth Amended and Restated Credit Agreement to the Credit Facility (the “Prior Credit Facility”) with a syndicate of lenders. The Prior Credit Facility provided for interest-only payments until May 25, 2023, when the Prior Credit Facility would mature and any outstanding borrowings would become due. The maximum credit amount under the Prior Credit Facility was $2.0 billion.

Effective May 1, 2019, the Company entered into the third amendment to the Prior Credit Facility to, among other things: (i) reaffirm the borrowing base at $1.1 billion, excluding the Ranger assets sold; and (ii) amend various covenants and terms to reflect current market trends.

As a result of entering into the Credit Facility, as defined below, the Company terminated the Prior Credit Facility. As a result of terminating the Prior Credit Facility, the Company recorded a loss on extinguishment of debt of $4.9 million, which was comprised solely of the write-off of unamortized deferred financing costs associated with the Prior Credit Facility.

On December 20, 2019, upon consummation of the Merger, the Company entered into the credit agreement with a syndicate of lenders (the “Credit Facility”). The Credit Facility provides for interest-only payments until December 20, 2024 (subject to springing maturity dates of (i) January 14, 2023 if the 6.25% Senior Notes are outstanding at such time and (ii) July 2, 2024 if the 6.125% Senior Notes are outstanding at such time), when the Credit Facility matures and any outstanding borrowings are due. The maximum credit amount under the Credit Facility is $5.0 billion. The borrowing base under the Credit Facility is subject to regular redeterminations in the spring and fall of each year, as well as special redeterminations described in the credit agreement, which in each case may reduce the amount of the borrowing base. The Credit Facility is secured by first preferred mortgages covering the Company’s major producing properties. The capitalized terms which are not defined in this description of the revolving credit facility shall have the meaning given to such terms in the credit agreement.

As of December 31, 2019, the borrowing base under the Credit Facility was $2.5 billion, with an elected commitment amount of $2.0 billion, and borrowings outstanding of $1.3 billion at a weighted average interest rate of 3.56%. The Company also had $17.7 million in letters of credit outstanding under the Credit Facility.

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 0.25% to 1.25%, 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 Eurodollar loan plus a margin between 1.25% to 2.25%. At any time the Leverage Ratio, as defined in the credit agreement, is greater than 3.00 to 1.00, the base rate and Eurodollar loans are increased 0.25%. The Company also incurs commitment fees at rates ranging between 0.375% to 0.500% as set forth in the table below on the unused portion of lender commitments, which are included in “Interest expense, net” in the consolidated statements of operations.

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. The Company used the net proceeds from the offering of approximately $394.0 million, after deducting initial purchasers’ discounts and estimated offering expenses, to fund a portion of the Delaware Asset Acquisition described above. The 6.375% 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. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

The Company may redeem the 6.375% Senior Notes in accordance with the following terms: (1) prior to July 1, 2021, 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 106.375% of principal, plus accrued and unpaid interest, if any, to the date of the redemption, if at least 65% of the principal will remain outstanding after such redemption; (2) prior to July 1, 2021, a redemption of all or part of the principal at a price of 100% of principal of the amount redeemed, plus an applicable make-whole premium and accrued and unpaid interest, if any, to the date of the redemption; and (3) a redemption, in whole or in part, at a redemption price, plus accrued and unpaid interest, if any, to the date of the redemption, (i) of 103.188% of principal if the redemption occurs on or after July 1, 2021, but before July 1, 2022, and (ii) of 102.125% of principal if the redemption occurs on or after July 1, 2022, but before July 1, 2023, and (iii) of 101.063% of principal if the redemption occurs on or after July 1, 2023, but before July 1, 2024, and (iv) of 100% of principal if the redemption occurs on or after July 1, 2024.

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.

6.125% Senior Notes

On October 3, 2016, the Company issued $400.0 million aggregate principal amount of 6.125% Senior Notes due 2024 (the “6.125% Senior Notes), which mature on October 1, 2024 and have interest payable semi-annually each April 1 and October 1. 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. The subsidiary guarantor is 100% owned, all of the guarantees are full and unconditional and joint and several, the parent company has no independent assets or operations and any subsidiaries of the parent company other than the subsidiary guarantor are minor.

On May 19, 2017, the Company issued an additional $200.0 million aggregate principal amount of its 6.125% Senior Notes which with the existing $400.0 million aggregate principal amount of 6.125% Senior Notes are treated as a single class of notes under the indenture. The Company used a portion of the net proceeds from the offering of approximately $206.1 million, including a premium issue price of 104.125% and after deducting initial purchasers’ discounts and estimated offering expenses, to fund the acquisition completed on June 5, 2017 with the remainder for general corporate purposes.

The Company may redeem all or a portion of the 6.125% Senior Notes at redemption prices decreasing from 104.594% to 100% of the principal amount on October 1, 2022, 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, if any, to the date of repurchase.

Senior Notes Assumed in Merger

On December 20, 2019, upon consummation of the Merger, the Company became successor-in-interest to the indenture governing the 8.25% Senior Notes due 2025 (the “8.25% Senior Notes”) and the 6.25% Senior Notes due 2023 (the “6.25% Senior Notes”). Both the 8.25% Senior Notes and the 6.25% Senior Notes are guaranteed on a senior unsecured basis by the Company’s wholly-owned subsidiary, Callon Petroleum Operating Company, and may be guaranteed by certain future subsidiaries.

8.25% Senior Notes. The 8.25% Senior Notes mature on July 15, 2025 and have interest payable semi-annually each January 15 and July 15. Before July 15, 2020, the Company may, at its option, redeem all or a portion of the 8.25% Senior Notes at 100% of the principal amount plus accrued and unpaid interest and a make-whole premium. Thereafter, 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.

6.25% Senior Notes. The 6.25% Senior Notes mature on April 15, 2023 and have interest payable semi-annually each April 15 and October 15. The Company may redeem all or a portion of the 6.25% Senior Notes at redemption prices decreasing from 103.125% to 100% of the principal amount on April 15, 2021, plus accrued and unpaid interest.

If a Change of Control (as defined in the indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes) occurs, the Company may be required by holders to repurchase the 8.25% Senior Notes and the 6.25% Senior Notes for cash at a price equal to 101% of the principal amount purchased, plus any accrued and unpaid interest. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes contains covenants that, among other things, limit the Company’s ability and the ability of its restricted subsidiaries to: pay distributions on, purchase or redeem the Company’s capital stock or redeem the Company’s subordinated debt; make investments; incur or guarantee additional indebtedness or issue certain types of equity securities; create certain liens; sell assets; consolidate, merge or transfer all or substantially all of the Company’s assets; enter into agreements that restrict distributions or other payments from the Company’s restricted subsidiaries to the Company; engage in transactions with affiliates; and create unrestricted subsidiaries. The indenture governing the 8.25% Senior Notes and the 6.25% Senior Notes also contains customary events of default, including those related to failure to comply with the terms of the 8.25% Senior Notes and the 6.25% Senior Notes, certain cross defaults of other indebtedness and mortgages, and certain failures to pay final judgments.

Restrictive covenants

The Company’s credit facility and the indentures governing its senior notes contain various covenants including restrictions on additional indebtedness, payment of cash dividends and maintenance of certain financial ratios. The Company was in compliance with these covenants at December 31, 2019.

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Revenue Recognition

12 Months Ended

Dec. 31, 2019

Revenue from Contract with Customer [Abstract]

Revenue Recognition

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.

Natural gas sales

Under the Company’s natural gas sales processing contracts, it delivers natural gas to a midstream processing entity. The midstream processing entity gathers and processes the natural gas and remits proceeds to the Company for the resulting sale of natural gas. The revenue received from the sale of NGLs associated with certain contracts is included in natural gas sales. Under these processing agreements, when control of the natural gas changes at the point of delivery, the treatment of gathering and treating fees are recorded net of revenues. For other contracts that were assumed in the Carrizo Acquisition, defined below, where the Company maintains control throughout processing, the Company records NGL revenue separately on its consolidated statement of operations and presents the gathering a treating fees as an expense recorded in lease operating expense.

For the majority of the Company’s natural gas sales processing contracts, gathering and treating fees have historically been recorded as an expense in lease operating expense in the statement of operations. The Company modified the presentation of revenues and expenses to include these fees net of revenues effective January 1, 2018 upon adopting ASC 606 - Revenue from Contracts with Customers. For the years ended December 31, 2019 and 2018, $10.5 million and $7.6 million of gathering and treating fees were recognized and recorded as a reduction to natural gas revenues in the consolidated statement of operations, respectively. For the year ended December 31, 2017, $3.4 million of gathering and treating fees were recognized and recorded as part of lease operating expense in the consolidated statement of operations.

Accounts receivable from revenues from contracts with customers

Net accounts receivable include amounts billed and currently due from revenues from contracts with customers of our oil and natural gas production, which had a balance at December 31, 2019 and 2018 of $165.3 million and $87.1 million, respectively, and are presented in “Accounts receivable, net” in the consolidated balance sheets. The increase from December 31, 2018 is primarily due to the Carrizo Acquisition.

Transaction price allocated to remaining performance obligations

For the Company’s product sales that have a contract term greater than one year, it has utilized the practical expedient in Accounting Standards Codification 606-10-50-14, which states the Company is not required to disclose the transaction price allocated to remaining performance obligations if the variable consideration is allocated entirely to a wholly unsatisfied performance obligation. Under these sales contracts, each unit of product generally represents a separate performance obligation; therefore future volumes are wholly unsatisfied and disclosure of the transaction price allocated to remaining performance obligations is not required.

Prior period performance obligations

The Company records revenue in the month production is delivered to the purchaser. However, settlement statements for sales may not be received for 30 to 90 days after the date production is delivered, and as a result, the Company is required to estimate the amount of production delivered to the purchaser and the price that will be received for the sale of the product. The Company records the differences between estimates and the actual amounts received for product sales in the month that payment is received from the purchaser. The Company has existing internal controls for its revenue estimation process and related accruals, and any identified differences between its revenue estimates and actual revenue received historically have not been significant.

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Borrowings (Tables)

12 Months Ended

Dec. 31, 2019

Debt Disclosure [Abstract]

Schedule of Borrowings

The Company’s borrowings consisted of the following:

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	As of December 31,
	2019			2018
	(In thousands)
Senior Secured Revolving Credit Facility due 2024		$1,285,000			$200,000
6.25% Senior Notes due 2023 (1)	650,000			—
6.125% Senior Notes due 2024	600,000			600,000
8.25% Senior Notes due 2025 (1)	250,000			—
6.375% Senior Notes due 2026	400,000			400,000
Total principal outstanding	3,185,000			1,200,000
Unamortized premium for 6.125% Senior Notes	5,344			6,469
Unamortized premium for 6.25% Senior Notes	4,838			—
Unamortized premium for 8.25% Senior Notes	5,286			—
Unamortized deferred financing costs for Senior Notes	(14,359		)	(16,996		)
Total carrying value of borrowings (2)		$3,186,109			$1,189,473

(1) As a result of the Merger, the Company became successor-in-interest to the indenture governing the 6.25% Senior Notes and 8.25% Senior Notes.

(2)

Excludes unamortized deferred financing costs related to the Company’s senior secured revolving credit facility of $22.2 million and $6.1 million as of December 31, 2019 and 2018, respectively.

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2019

Income Tax Disclosure [Abstract]

Schedule of Components of Income Tax Expense (Benefit)

The components of the Company’s income tax expense are as follows:

	Years Ended December 31,
	2019		2018		2017
	(In thousands)
Current
Federal		$—		$—		($48	)
State	220		—		—
Total current income tax expense (benefit)	220		—		(48		)
Deferred
Federal	33,584		3,594		(45		)
State	1,497		4,516		1,366
Total deferred income tax expense	35,081		8,110		1,321
Total income tax expense		$35,301		$8,110		$1,273

Schedule of Effective Income Tax Rate Reconciliation

A reconciliation of the income tax expense calculated at the federal statutory rate of 21% in 2019 and 2018 and 35% in 2017, to income tax expense is as follows:

	Years Ended December 31,
	2019		2018			2017
Income before income taxes		$103,229		$308,470			$121,697
Income tax expense computed at the statutory federal income tax rate	21,678		64,779			42,594
State income tax expense, net of federal benefit	1,253		3,568			1,273
Equity based compensation	1,222		(494		)	—
Non-deductible compensation	90		1,209			—
Non-deductible merger expenses	5,537		—			—
Statutory depletion carryforward	5,381		—			—
Other	140		168			—
Change in valuation allowance	—		(61,120		)	(42,594		)
Income tax expense		$35,301		$8,110			$1,273

Schedule of Deferred Tax Assets and Liabilities

	As of December 31,
	2019			2018
	(In thousands)
Deferred tax assets
Federal net operating loss carryforward		$110,703			$151,497
Interest expense carryforward	—			7,335
Statutory depletion carryforward	—			5,381
Asset retirement obligations	9,981			2,347
Derivative asset	14,823			—
Unvested RSU equity awards	4,928			2,751
Operating lease right-of-use assets	29,897			—
Other	10,445			991
Total deferred tax assets		$180,777			$170,302
Deferred income tax valuation allowance	—			—
Net deferred tax assets		$180,777			$170,302
Deferred tax liability
Oil and natural gas properties		($38,546	)		($169,682	)
Derivative liability	—			(10,184		)
Operating lease liabilities	(26,511		)	—
Total deferred tax liability		($65,057	)		($179,866	)
Net deferred tax asset (liability)		$115,720			($9,564	)