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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)
_______________________________________________
໿
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


 
 

 
9

 
10

 

 
Drilling Activity

 
Productive Wells
14

 
15

 
Major Customers
16

 

 

 
18

 

 





 
 


 



 

 
Overview

 

 
48

 
Summary of Critical Accounting Policies



 

 

 

 

 

 

 
Supplemental Information on Oil and Natural Gas Operations (Unaudited)

 
Supplemental Quarterly Financial Information (Unaudited)




 
 


104

104

104

104

 
 

105

108

 
109


2


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.

3


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.

4


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.

5



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. 

6


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;

7


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.

8


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.

9


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.

10


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.

11


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. 
໿
 
 
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.

17


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

18


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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