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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: 1-33615
Concho Resources Inc.
(Exact name of registrant as specified in its charter)
Delaware
 
76-0818600
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer Identification No.)
 
 
 
 
One Concho Center
 
 
600 West Illinois Avenue
 
 
Midland
Texas
 
79701
(Address of principal executive offices)
 
(Zip Code)
 
(432)
683-7443
 
(Registrant’s telephone number, including area code)
Securities Registered Pursuant to Section 12(b) of the Act:
Title of each class
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Stock, $0.001 par value
 
CXO
 
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 þ 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 þ
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 þ  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 þ 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 þ
Aggregate market value of the voting and non-voting common equity held by non-affiliates computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of the registrant’s most recently completed second fiscal quarter:
$
20,479,372,863

 
 
Number of shares of the registrant's common stock outstanding as of February 14, 2020
196,705,121

Documents Incorporated by Reference
Portions of the registrant’s definitive proxy statement for its 2020 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2019, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, 2019.
 


Table of Contents

TABLE OF CONTENTS
 
 
 
 

i

Table of Contents

 
 
 
 
 
 


ii

Table of Contents

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS
Various statements and information contained in or incorporated by reference into this report that express a belief, expectation, or intention, or that are not statements of historical fact, are forward-looking statements within the meaning of Section 27A of the Securities Act of 1933, as amended, and Section 21E of the Securities Exchange Act of 1934, as amended (the “Exchange Act”). These forward-looking statements include statements, projections and estimates concerning our future financial position, operations, performance, business strategy, oil and natural gas reserves, drilling program, production, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of regulation and disputes. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “will,” “goal” or other words that convey future events, expectations or possible outcomes. Forward-looking statements are not guarantees of performance. We have based these forward-looking statements on our current expectations and assumptions about future events and their potential effect on us. These statements are based on certain assumptions and analyses made by us in light of our experience and our perception of historical trends, current conditions and expected future developments as well as other factors we believe are appropriate under the circumstances. Actual results may differ materially from those implied or expressed by any forward-looking statements. These forward-looking statements speak only as of the date of this report, or if earlier, as of the date they were made. We disclaim any obligation to update or revise these statements unless required by law, whether as a result of new information, future events or otherwise, and we caution you not to rely on them unduly. While our management considers these expectations and assumptions to be reasonable, they are inherently subject to significant business, economic, competitive, regulatory and other risks, contingencies and uncertainties relating to, among other matters, the risks discussed in “Item 1A. Risk Factors” in this report, as well as those factors summarized below:
declines in, the sustained depression of, or increased volatility in the prices we receive for our oil and natural gas, or increases in the differential between index oil or natural gas prices and prices received;
the effects of government regulation, permitting and other legal requirements, including new legislation or regulation related to hydraulic fracturing and climate change;
competition in the oil and natural gas industry;
disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil and natural gas and other processing and transportation considerations;
drilling, completion and operating risks, including our ability to efficiently execute large-scale project development as we could experience delays, curtailments and other adverse impacts associated with well spacing and a high concentration of activity;
uncertainties about the estimated quantities of oil and natural gas reserves;
risks related to the concentration of our operations in the Permian Basin of West Texas and Southeast New Mexico;
uncertainties about our ability to successfully execute our business and financial plans and strategies;
uncertainty concerning our assumed or possible future results of operations;
evolving cybersecurity risks, such as those involving unauthorized access or control, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions;
environmental hazards, such as uncontrollable flows of oil, natural gas, saltwater, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
general economic and business conditions, either internationally or domestically;
the costs and availability of equipment, resources, services and qualified personnel required to perform our drilling, completion and operating activities;
risks associated with acquisitions such as increased expenses and integration efforts, failure to realize the expected benefits of the transaction and liabilities associated with acquired properties or businesses;
risks related to ongoing expansion of our business, including the recruitment and retention of qualified personnel in the Permian Basin;
the impact of current and potential changes to federal or state tax rules and regulations;
potential financial losses or earnings reductions from our commodity price risk-management program;
difficult and adverse conditions in the domestic and global capital and credit markets;
the adequacy of our capital resources and liquidity including, but not limited to, access to additional borrowing capacity under our Credit Facility, as defined herein;
the impact of potential changes in our credit ratings; and
uncertainties about our ability to replace reserves and economically develop our current reserves.
Reserve engineering is a process of estimating underground accumulations of oil and natural gas that cannot be measured in an exact way. The accuracy of any reserve estimate depends on the quality of available data, the interpretation of such data and the price and cost assumptions made by our reserve engineers. In addition, the results of drilling, testing and production activities may justify revisions of estimates that were made previously. If significant, such revisions would change the schedule of any further production and development drilling. Accordingly, reserve estimates may differ from the quantities of oil and natural gas that are ultimately recovered.

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PART I
Item 1. Business
General
Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) incorporated in February 2006, is an independent oil and natural gas company engaged in the acquisition, development, exploration and production of oil and natural gas properties. Our operations are primarily focused in the Permian Basin of West Texas and Southeast New Mexico. The Permian Basin is one of the most prolific oil and natural gas producing regions in the United States and is characterized by an extensive production history, long reserve life, multiple producing horizons and significant recovery potential. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends, and we are actively developing our resource base utilizing long-lateral wells and multi-well pad locations.
Business and Properties
Our operations are focused in the Permian Basin, which underlies an area of West Texas and Southeast New Mexico approximately 250 miles wide and 300 miles long. Commercial accumulations of hydrocarbons occur in multiple stratigraphic horizons, at depths ranging from less than 1,000 feet to over 25,000 feet. At December 31, 2019, our 1,002 MMBoe total estimated proved reserves were approximately 74 percent proved developed, as compared to proved developed reserves of approximately 69 percent of total estimated proved reserves of 1,187 MMBoe at December 31, 2018. Our total estimated proved reserves at December 31, 2019 consisted of approximately 62 percent oil and 38 percent natural gas.
We have one operating segment and one reporting unit, which is oil and natural gas development, exploration and production. All of our operations are conducted in one geographic area of the United States.
On July 19, 2018, we completed the acquisition of RSP Permian, Inc. (“RSP”) through an all-stock transaction (the “RSP Acquisition”). RSP was an independent oil and natural gas company engaged in the acquisition, exploration, development and production of oil and natural gas reserves in the Permian Basin. The vast majority of RSP’s acreage was located on large, contiguous acreage blocks in the core of the Midland Basin and the Delaware Basin. The acquisition added approximately 92,000 net acres to our asset portfolio.
The following table summarizes our drilling activity during the periods indicated:
 
Years Ended December 31,
2019
 
2018
 
2017
Gross wells
454

 
428

 
311

Net wells
257

 
266

 
197

 
 
 
 
 
 
Percent of gross wells drilled horizontally
100
%
 
100
%
 
100
%
 
 
 
 
 
 
Percent of gross wells:
 
 
 
 
 
Productive
55
%
 
44
%
 
61
%
Unsuccessful
%
 
%
 
1
%
Awaiting completion at year end
45
%
 
56
%
 
38
%
 
100
%
 
100
%
 
100
%
 

Summary of Operating Areas
The following is a summary of information regarding our operating areas:
Operating Areas
 
December 31, 2019
 
Estimated
Proved
Reserves
(MMBoe)
 
% Oil
 
% Proved
Developed
 
Total
Gross
Acreage
(in thousands)
 
Total
Net
Acreage
(in thousands)
 
2019 Average
Daily
Production
(MBoe per Day)
Delaware Basin
 
556
 
61
%
 
76
%
 
524
 
352
 
217
Midland Basin
 
446
 
63
%
 
73
%
 
285
 
197
 
114
Total
 
1,002
 
62
%
 
74
%
 
809
 
549
 
331
 

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Operating areas
Our operations are focused in the Delaware Basin and the Midland Basin, within the greater Permian Basin. Our development in both areas includes large-scale, full-field development to maximize resource recovery and program economics while optimizing well spacing, landing intervals, lateral length and completion techniques.
Delaware Basin. At December 31, 2019, we had estimated proved reserves in this area of 556 MMBoe, representing 55 percent of our total proved reserves. During the year ended December 31, 2019, we commenced drilling or participated in the drilling of 299 (148 net) wells in this area, and we completed 294 (176 net) wells that are producing.
Our activity in 2019 was centered mostly on continued development of our assets, with an emphasis on multi-well pad sites and extended lateral lengths to develop multiple producing formations. We primarily target the Avalon, Bone Spring and Wolfcamp formations, which generally range from 6,500 feet to 13,500 feet.
Midland Basin. At December 31, 2019, we had estimated proved reserves in this area of 446 MMBoe, representing 45 percent of our total proved reserves. During the year ended December 31, 2019, we commenced drilling or participated in the drilling of 155 (109 net) wells in this area, and we completed 185 (131 net) wells that are producing.
Our primary objectives in the Midland Basin area are the Spraberry and Wolfcamp formations, which generally range from 7,500 feet to 11,500 feet. We are developing these formations with horizontal drilling, utilizing multi-well pad sites and extended lateral development.
Drilling Activities
The following table sets forth information with respect to (i) wells drilled and completed during the periods indicated and (ii) wells drilled in a prior period but completed in the periods indicated. The information should not be considered indicative of future performance, nor should a correlation be assumed between the number of productive wells drilled, quantities of reserves found or economic value.
 
Years Ended December 31,
2019
 
2018
 
2017
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
Development wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
151

 
124

 
114

 
80

 
96

 
76

Dry

 

 

 

 
1

 
1

Exploratory wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
328

 
183

 
236

 
124

 
209

 
112

Dry
3

 
2

 
1

 
1

 
3

 
3

Total wells:
 
 
 
 
 
 
 
 
 
 
 
Productive
479

 
307

 
350

 
204

 
305

 
188

Dry (a)
3

 
2

 
1

 
1

 
4

 
4

Total
482

 
309

 
351

 
205

 
309

 
192

 
(a)
The dry hole category includes 2 (1 net) wells and 1 (1 net) well that were unsuccessful due to mechanical issues for the years ended December 31, 2019 and 2018, respectively. Additionally, the dry hole category includes 1 (1 net) well that was incapable of producing hydrocarbons in economic quantities for the year ended December 31, 2019.
 
 
 
 
 
Present activities. The following table sets forth information about wells for which drilling was in-progress or are pending completion at December 31, 2019, which are not included in the above table:
 
Drilling In-Progress
 
Pending Completion
Gross
 
Net
 
Gross
 
Net
Development and exploratory wells
34

 
21

 
157

 
95

 

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Table of Contents

Our Production, Prices and Expenses
The following table sets forth a summary of our production and operating data for the years ended December 31, 2019, 2018 and 2017. The actual historical data in this table excludes results from the RSP Acquisition for periods prior to July 19, 2018. Because of normal production declines, increased or decreased drilling activities, fluctuations in commodity prices and the effects of acquisitions or divestitures, the historical information presented below should not be interpreted as being indicative of future results.
 
Years Ended December 31,
 
2019
 
2018
 
2017
Production and operating data:
 
 
 
 
 
Net production volumes:
 
 
 
 
 
Oil (MBbl)
76,369

 
61,251

 
43,472

Natural gas (MMcf)
266,865

 
208,326

 
161,089

Total (MBoe)
120,847

 
95,972

 
70,320

 
 
 
 
 
 
Average daily production volumes:
 
 
 
 
 
Oil (Bbl)
209,230

 
167,811

 
119,101

Natural gas (Mcf)
731,137

 
570,756

 
441,340

Total (Boe)
331,086

 
262,937

 
192,658

 
 
 
 
 
 
Average prices per unit: (a)
 
 
 
 
 
Oil, without derivatives (Bbl)
$
54.03

 
$
56.22

 
$
48.13

Oil, with derivatives (Bbl) (b)
$
52.35

 
$
52.73

 
$
49.93

Natural gas, without derivatives (Mcf)
$
1.74

 
$
3.40

 
$
3.07

Natural gas, with derivatives (Mcf) (b)
$
1.86

 
$
3.37

 
$
3.06

Total, without derivatives (Boe)
$
38.00

 
$
43.25

 
$
36.78

Total, with derivatives (Boe) (b)
$
37.19

 
$
40.98

 
$
37.88

 
 
 
 
 
 
Operating costs and expenses per Boe: (a)
 
 
 
 
 
Oil and natural gas production
$
5.93

 
$
6.14

 
$
5.80

Production and ad valorem taxes
$
2.89

 
$
3.19

 
$
2.82

Gathering, processing and transportation
$
0.96

 
$
0.58

 
$

Depreciation, depletion and amortization
$
16.25

 
$
15.41

 
$
16.29

General and administrative
$
2.69

 
$
3.25

 
$
3.46

 
 
 
 
 
 
 
 
(a)
Per unit and per Boe amounts calculated using dollars and volumes rounded to thousands.
 
 
 
 
 
 
 
 
 
(b)
Includes the effect of net cash receipts from (payments on) derivatives:
 
 
 
 
 
 
Years Ended December 31,
 
 
(in millions)
2019
 
2018
 
2017
 
 
Net cash receipts from (payments on) derivatives:
 
 
Oil derivatives
$
(129
)
 
$
(213
)
 
$
79

 
 
Natural gas derivatives
31

 
(5
)
 

 
 
Total
$
(98
)
 
$
(218
)
 
$
79

 
 
 
 
 
The presentation of average prices with derivatives is a result of including the net cash receipts from (payments on) commodity derivatives that are presented in our consolidated statements of cash flows. This presentation of average prices with derivatives is a means by which to reflect the actual cash performance of our commodity derivatives for the respective periods and presents oil and natural gas prices with derivatives in a manner consistent with the presentation generally used by the investment community.
 
 
 
 
 
 


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Productive Wells
The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2019, 2018 and 2017. The change in gross and net wells for 2019 as compared to 2018 is primarily attributable to the New Mexico Shelf divestiture. See Note 5 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information. As of December 31, 2019, we did not have any wells with multiple completions. This table does not include wells in which we own a royalty interest only.
 
Gross Productive Wells
 
Net Productive Wells
Oil
 
Natural
Gas
 
Total
 
Oil
 
Natural
Gas
 
Total
December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
Operating Areas:
 
 
 
 
 
 
 
 
 
 
 
Delaware Basin
1,991

 
574

 
2,565

 
1,216

 
279

 
1,495

Midland Basin
3,397

 
16

 
3,413

 
2,255

 
5

 
2,260

Other

 
3

 
3

 

 

 

Total
5,388

 
593

 
5,981

 
3,471

 
284

 
3,755

 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2018
 
 
 
 
 
 
 
 
 
 
 
Operating Areas:
 
 
 
 
 
 
 
 
 
 
 
Delaware Basin
4,801

 
690

 
5,491

 
3,569

 
313

 
3,882

Midland Basin
3,770

 
13

 
3,783

 
2,437

 
4

 
2,441

Other

 
3

 
3

 

 

 

Total
8,571

 
706

 
9,277

 
6,006

 
317

 
6,323

 
 
 
 
 
 
 
 
 
 
 
 
December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
Operating Areas:
 
 
 
 
 
 
 
 
 
 
 
Delaware Basin
4,801

 
586

 
5,387

 
3,469

 
274

 
3,743

Midland Basin
2,747

 
15

 
2,762

 
1,675

 
6

 
1,681

Other

 
3

 
3

 

 

 

Total
7,548

 
604

 
8,152

 
5,144

 
280

 
5,424

 

Marketing Arrangements
General. We market our oil and natural gas in accordance with standard energy industry practices. Through our marketing efforts we endeavor to obtain the combined highest netback and most secure market available at that time. In addition, marketing supports our operations group as it relates to the planning and preparation of future development activity so that available markets can be assessed and secured.
Oil. We generally sell production at the lease to third-party purchasers. We generally do not transport, refine or process the oil we produce. Most of our Delaware Basin production in New Mexico is connected to the Plains Pipeline, L.P. gathering system. This production is then primarily purchased by three different purchasers.
Most of our Delaware Basin production in Texas is connected to one of five different gathering systems. A significant portion of our Midland Basin production is on one of nine different gathering systems. The remaining portion of our production is sold via truck transport. We sell our produced oil under contracts using market-based pricing, which is adjusted for differentials based upon delivery location and oil quality.
Natural Gas. We consider all natural gas gathering, treating and processing service providers in the areas of our production and evaluate market options to obtain the best price reasonably available given the necessary operating conditions. We sell the majority of our natural gas under individually negotiated natural gas purchase contracts using market-based pricing. The majority of our natural gas is subject to long-term agreements that generally extend five to ten years from the effective date of the subject contract.
The majority of our natural gas is casing head gas, which is sold at the lease location under (i) percentage of proceeds processing contracts, (ii) fee-based contracts or (iii) a hybrid of percentage of proceeds and fee-based contracts. The purchasers generally gather our casinghead natural gas in the field where it is produced and then transport it via pipeline to natural gas processing plants where natural gas liquid products and residue gas are extracted and sold. Under our percentage of proceeds and hybrid percentage of proceeds and fee-based contracts, we receive a percentage of the value for the extracted liquids and the residue gas. Under our fee-based contracts, we receive natural gas liquids and residue gas value, less the fee component thereof, or are invoiced the fee component of the purchaser’s service.

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Delivery Commitments
Certain of our firm sales agreements for both oil and natural gas include delivery commitments. We believe our current production and reserves are sufficient to fulfill these delivery commitments. See Note 11 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for more information.
Our Principal Customers
We sell our oil and natural gas production principally to marketers and other purchasers that have access to pipeline facilities. In areas where there is no practical access to pipelines, oil is transported to storage facilities by trucks owned or otherwise arranged by the marketers or purchasers. Our marketing of oil and natural gas can be affected by factors beyond our control, the effects of which cannot be accurately predicted.
For 2019, revenues from oil and natural gas sales to Plains Marketing and Transportation, Inc. and Enterprise Crude Oil LLC accounted for approximately 17 percent and 10 percent of our total operating revenues, respectively. While the loss of either purchaser may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions. See Note 13 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data.”
Competition
The oil and natural gas industry in the areas in which we operate is highly competitive. We encounter strong competition from numerous parties, ranging generally from small independent producers to major integrated companies. We primarily encounter significant competition in acquiring properties. At higher commodity prices, we also face competition in contracting for drilling, pressure pumping and workover equipment and securing and retaining qualified personnel. Many of these competitors have financial, technical and personnel resources substantially larger than ours. As a result, our competitors may be able to pay more for desirable properties, or to evaluate, bid for and purchase a greater number of properties or prospects than our financial or personnel resources will permit.
In addition to competition for drilling, pressure pumping and workover equipment, we are also affected by the availability of related equipment and materials. The oil and natural gas industry periodically experiences shortages of drilling and workover rigs, equipment, pipe, materials and personnel, which can delay drilling, workover and exploration activities and cause significant price increases. We are not experiencing material shortages at this time but are unable to predict the timing or duration of any such future shortages.
Working Capital
Based on current market conditions, we have maintained a stable liquidity position. Our principal source of liquidity is available borrowing capacity under our credit facility, as amended and restated (our “Credit Facility”). At December 31, 2019, we had a cash balance of $70 million and did not have any borrowings under our Credit Facility. Additionally, we had approximately $2.0 billion of unused commitments under our Credit Facility. Our primary needs for cash are development, exploration and acquisitions of oil and natural gas assets, payment of contractual obligations and working capital obligations. However, additional borrowings under our Credit Facility or the issuance of additional debt securities will require a greater portion of our cash flow from operations to be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions.

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Applicable Laws and Regulations
Regulation of Production
The production of oil and natural gas is subject to regulation under a wide range of local, state and federal statutes, rules, orders and regulations. Federal, state and local statutes and regulations require permits for drilling operations, drilling bonds and reports concerning operations. All of the states in which we own and operate properties have regulations governing conservation matters, including provisions for the unitization or pooling of oil and natural gas properties, the establishment of maximum allowable rates of production from oil and natural gas wells, the regulation of well spacing, and the plugging and abandonment of wells. The effect of these regulations is to limit the amount of oil and natural gas that we can produce from our wells and to limit the number of wells or the locations at which we can drill, although we can apply for exceptions to such regulations or to have reductions in well spacing. 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. The failure to comply with these rules and regulations can result in substantial penalties. Our competitors in the oil and natural gas industry are subject to the same regulatory requirements and restrictions that affect our operations.
Environmental, Health and Safety Matters
General. Our operations are subject to stringent and complex federal, state and local laws and regulations governing environmental protection as well as the discharge of materials into the environment. These laws, rules and regulations may, among other things:
require the acquisition of various permits before drilling commences;
require notice to stakeholders of proposed and ongoing operations;
require the installation of emission control equipment;
restrict the types, quantities and concentration of various substances that can be released into the environment in connection with oil and natural gas drilling and production and saltwater disposal activities;
limit or prohibit drilling activities on certain lands lying within wilderness, wetlands and other protected areas, or otherwise restrict or prohibit activities that could impact the environment, including water resources; and
require remedial measures to mitigate pollution from former and ongoing operations, such as requirements to close pits and plug abandoned wells.
These laws, rules and regulations may also restrict the production rate of oil and natural gas below the rate that would otherwise be possible. The regulatory burden on the oil and natural gas industry increases the cost of doing business in the industry and consequently affects profitability. Violations and liabilities with respect to these laws and regulations could result in significant administrative, civil or criminal penalties, remedial clean-ups, natural resource damages, permit modifications or revocations, operational interruptions or shutdowns and other liabilities. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and leasehold acreage. Additionally, environmental laws and regulations are revised frequently, and any changes, including changes in implementation or interpretation, that result in more stringent and costly waste handling, disposal and cleanup requirements for the oil and natural gas industry could have a significant impact on our operating costs.
The following is a summary of some of the existing laws, rules and regulations to which our business is subject.
Waste handling. The Resource Conservation and Recovery Act (“RCRA”) and comparable state statutes regulate the generation, transportation, treatment, storage, disposal and cleanup of hazardous and non-hazardous wastes. Pursuant to regulatory guidance issued by the federal Environmental Protection Agency (the “EPA”), the individual states administer some or all of the provisions of RCRA, sometimes in conjunction with their own, more stringent requirements. Drilling fluids, produced waters, and most of the other wastes associated with the exploration, development, and production of oil or natural gas are currently regulated under RCRA’s non-hazardous waste provisions. However, it is possible that certain oil and natural gas exploration and production wastes now classified as non-hazardous could be classified as hazardous wastes in the future. Also, in the course of our operations, we generate some amounts of ordinary industrial wastes, such as paint wastes, waste solvents and waste oils that may be regulated as hazardous wastes if such wastes have hazardous characteristics.
Comprehensive Environmental Response, Compensation and Liability Act. The Comprehensive Environmental Response Compensation and Liability Act (“CERCLA”), also known as the Superfund law, imposes joint and several liability, without regard to fault or legality of conduct, on classes of persons who are considered to be responsible for the release of a hazardous substance into the environment. These persons include the current or former owner or operator of the site where the release occurred, and anyone who disposed or arranged for the disposal of a hazardous substance released at the site. Under CERCLA, such persons may be subject to strict, joint and several liability for the costs of cleaning up the hazardous substances that have been released into the environment, for damages to natural resources and for the costs of certain health studies. In addition, it is

7

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not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the hazardous substances released into the environment. Each state also has environmental cleanup laws analogous to CERCLA.
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 that we have utilized operating and waste 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 off-site locations, where such substances have been taken for disposal. In addition, some of our properties have been operated by third parties or by previous owners or operators whose storage, 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. Under such laws, we could be required to remove previously disposed substances and wastes, remediate contaminated property, or perform remedial operations to prevent future contamination.
Water discharges. The federal Water Pollution Control Act (the “Clean Water Act”) and analogous state laws, impose restrictions and strict controls with respect to the discharge of pollutants, including spills and leaks of oil and other substances, into waters of the United States. The discharge of pollutants into regulated waters, including dredge and fill activities in regulated wetlands, is prohibited, except in accordance with the terms of a permit issued by the EPA, or, in some circumstances, the U.S. Army Corps of Engineers (the “Corps”), or an analogous state agency. In addition, spill prevention, control and countermeasure requirements under federal law require appropriate containment berms and similar structures to help prevent the contamination of navigable waters in the event of a petroleum hydrocarbon tank spill, rupture or leak. Further, the Clean Water Act and analogous state laws require individual permits or coverage under general permits for discharges of storm water runoff from certain types of facilities. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with discharge permits or other requirements of the Clean Water Act and analogous state laws and regulations. On January 23, 2020, the EPA and the Corps issued the “Navigable Waters Protection Rule,” which narrows the scope of waters federally regulated under the Clean Water Act. The former regulation that had attempted to define the scope of the “Waters of the United States” (the “2015 Rule”) was repealed in 2019. Litigation over the “Navigable Water Protection Rule” and the repeal of the 2015 Rule are expected to continue. An expansion of the scope of the definition of jurisdictional waters subject to regulation under the Clean Water Act could increase our compliance costs.
Safe Drinking Water Act. Our oil and natural gas exploration and production operations generate produced water, drilling muds, and other waste streams, some of which may be disposed via injection in underground wells situated in non-producing subsurface formations. The drilling and operation of these injection wells are regulated by the federal Safe Drinking Water Act (the “SDWA”). The Underground Injection Well Program under the SDWA requires that we obtain permits from the EPA or delegated state agencies for our disposal wells, establishes minimum standards for injection well operations, restricts the types and quantities of fluids that may be injected and prohibits the migration of fluid containing any contaminants into underground sources of drinking water. Any leakage from the subsurface portions of the injection wells may cause degradation of freshwater, potentially resulting in cancellation of operations of a well, imposition of fines and penalties from governmental agencies, incurrence of expenditures for remediation of affected resources, and imposition of liability by landowners or other parties claiming damages for alternative water supplies, property damages, and personal injuries. Any changes in the laws or regulations or the inability to obtain permits for new injection wells in the future may affect our ability to dispose of produced waters and would ultimately increase the cost of our operations, which costs could be significant. For example, in 2014 the Railroad Commission of Texas (the “RRC”) adopted additional permit rules for injection wells to address seismic activity concerns within the state. Among other things, the rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells, and allow the RRC to modify, suspend, or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. Furthermore, in response to recent seismic events near underground injection wells used for the disposal of oil and natural gas-related wastewaters, federal and some state agencies have begun investigating whether such wells have caused increased seismic activity, and some states have shut down or imposed moratoria on the use of such injection wells. If new regulatory initiatives are implemented that restrict or prohibit the use of underground injection wells in areas where we rely upon the use of such wells in our operations, our costs to operate may significantly increase, and our ability to continue production may be delayed or limited, which could have a material adverse effect on our results of operations and financial position.
Air emissions. The federal Clean Air Act (the “CAA”), and comparable state laws regulate emissions of various air pollutants through air emissions permitting programs and the imposition of other requirements. New facilities may be required to obtain permits before work can begin, and existing facilities may be required to obtain additional permits and incur capital costs in order to remain in compliance. These and other laws and regulations may increase the costs of compliance for some facilities where we operate. Obtaining or renewing permits also has the potential to delay the development of our projects. Federal and state regulatory agencies can impose administrative, civil and criminal penalties for non-compliance with air permits or other requirements of the CAA and associated state laws and regulations. In addition, the EPA has developed, and continues to develop, stringent regulations governing emissions of toxic air pollutants at specified sources. These air emission rules have the potential to increase our compliance costs.
Climate change. In response to findings that emissions of carbon dioxide, methane and other “greenhouse gases” (“GHGs”) present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG

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emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. Both the EPA and the U.S. Bureau of Land Management (the “BLM”) finalized rules in 2016 that limit methane emissions from upstream oil and natural gas exploration and production operations. Increased regulation of methane and other GHGs have the potential to result in increased compliance costs and, consequently, adversely affect our operations. In addition, in August 2019, the EPA issued the Affordable Clean Energy rule (“ACE”) that designates heat rate improvement, or efficiency improvement, as the best system of emissions reduction for carbon dioxide from existing coal-fired electric utility generating units.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In addition, in 2015, the United States participated in the United Nations Conference on Climate Change, which led to the creation of the Paris Agreement. The Paris Agreement requires countries to review and “represent a progression” in their intended nationally determined contributions, which set GHG emission reduction goals, every five years beginning in 2020. However, in June 2017, President Trump announced that the United States plans to withdraw from the Paris Agreement and seek negotiations either to reenter the Paris Agreement on different terms or establish a new framework agreement. The Paris Agreement provides for a four-year exit process beginning in November 2016, which would result in an effective exit date of November 2020. The United States’ adherence to the exit process or the terms on which the United States may reenter the Paris Agreement or a separately negotiated agreement are unclear at this time.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances, or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also increase the cost of consuming, and thereby reduce demand for, the oil and natural gas we produce. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. Consequently, legislation and regulatory programs to reduce emissions of GHGs could have an adverse effect on our business, financial condition and results of operations. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and gas companies in connection with their GHG emissions. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to our causation of or contribution to the asserted damage, or to other mitigating factors.
Hydraulic fracturing. Hydraulic fracturing is an important and common practice that is used to stimulate production of oil and/or natural gas from dense subsurface rock formations. The hydraulic fracturing process involves the injection of water, sand, and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. We routinely use hydraulic fracturing as part of our operations. The process is typically regulated by state oil and natural gas commissions, but the EPA has asserted federal regulatory authority pursuant to the SDWA over certain hydraulic fracturing activities involving the use of diesel and issued guidance in February 2014 governing such activities. The EPA has also issued final regulations under the CAA establishing performance standards, including standards for the capture of volatile organic compounds (“VOCs”) and methane released during hydraulic fracturing (although the EPA has temporarily suspended or delayed compliance with certain of these standards as they undergo an administrative review); an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 that prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants.
At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico and Texas have adopted hydraulic fracturing fluid disclosure requirements, and the RRC has also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and natural gas activities occurring within their boundaries. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
We do not have insurance policies in effect that are intended to provide coverage for losses solely related to hydraulic fracturing operations; however, we believe our well control, general liability and excess liability insurance policies may cover third-party claims related to hydraulic fracturing operations and associated legal expenses in accordance with, and subject to, the terms of such policies. If new laws or regulations significantly restrict hydraulic fracturing activities or impose burdens on new permitting or operating requirements, our ability to utilize hydraulic fracturing may be curtailed, and this may in turn reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.

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Operations on Federal Lands. We currently operate on federal lands under the jurisdiction of the BLM. Permitting for oil and natural gas activities on federal lands can take significantly longer than the state permitting process. Delays in obtaining permits necessary can disrupt our operations and have an adverse effect on our business. In November 2016, the BLM finalized rules that restrict methane emissions from oil and natural gas activities on federal lands by limiting venting and flaring of natural gas from wells and other equipment. The final rule also requires operators to pay royalties to the BLM on flared gas from wells already connected to gas capture infrastructure, and allows the agency to set royalty rates at or above 12.5 percent of the value of production. These rules could result in increased compliance costs for our operations, which in turn could have an adverse effect on our business and results of operations.
Endangered species. The federal Endangered Species Act (the “ESA”) and analogous state laws regulate activities that could have an adverse effect on threatened or endangered species. Some of our drilling operations are conducted in areas where protected species are known to exist. In these areas, we may be obligated to develop and implement plans to avoid potential adverse impacts to protected species, and we may be prohibited from conducting drilling operations in certain locations or during certain seasons, such as breeding and nesting seasons, when our operations could have an adverse effect on the species. It is also possible that a federal or state agency could order a complete halt to drilling activities in certain locations if it is determined that such activities may have a serious adverse effect on a protected species. The presence of a protected species in areas where we perform drilling activities could impair our ability to timely complete drilling and developmental operations and could adversely affect our future production from those areas. The designation of previously unprotected species as threatened or endangered in areas where we or our oil and natural gas exploration and production customers operate could cause us or our customers to incur increased costs arising from species protection measures and could result in delays or limitations in our customers’ performance of operations.
National Environmental Policy Act. Oil and natural gas exploration and production activities on federal lands are subject to the National Environmental Policy Act (“NEPA”). NEPA 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. All of 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 even halt development of some of our oil and natural gas projects.
OSHA and other laws and regulations. We are subject to the requirements of the federal Occupational Safety and Health Act (“OSHA”) and comparable state statutes. The OSHA hazard communication standard, the EPA community right-to-know regulations under Title III of CERCLA and similar state statutes require that we organize and/or disclose information about hazardous materials used or produced in our operations. Also, pursuant to OSHA, the Occupational Safety and Health Administration has established a variety of standards relating to workplace exposure to hazardous substances and employee health and safety.
We are not aware of any existing environmental issues, claims or regulations that will require us to incur material capital expenditures during 2020, and we did not incur material capital expenditures relating to environmental issues, claims or regulations during 2019. However, we cannot assure that the passage or application of more stringent laws or regulations or the application of existing laws in the future will not require us to incur material capital expenditures or have a material adverse effect on our financial position or results of operations.

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Our Employees
Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue, Midland, Texas 79701 and have administrative offices in both Houston, Texas and Dallas, Texas. We also maintain various field offices in Texas and New Mexico. At December 31, 2019, we had 1,453 employees, 511 of whom were employed in field operations. Our future success will depend partially on our ability to attract, retain and motivate qualified personnel. We are not a party to any collective bargaining agreements and have not experienced any strikes or work stoppages. We consider our relations with our employees to be good.
Available Information
We file or furnish annual, quarterly and current reports, proxy statements and other documents with the U.S. Securities and Exchange Commission (the “SEC”) under the Exchange Act. The public can obtain any documents that we file with the SEC at www.sec.gov. We also make available free of charge through our website, www.concho.com, our reports that we file or furnish with the SEC as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.
Non-GAAP Financial Measures and Reconciliations
Reconciliation of Standardized Measure to PV-10
PV-10 is derived from the standardized measure of discounted future net cash flows, which is the most directly comparable GAAP financial measure. PV-10 is a computation of the standardized measure of discounted future net cash flows on a pre-tax basis. PV-10 is equal to the standardized measure of discounted future net cash flows at the applicable date, before deducting future income taxes, discounted at 10 percent. We believe that the presentation of PV-10 is relevant and useful to investors because it presents the discounted future net cash flows attributable to our estimated proved reserves prior to taking into account future corporate income taxes, and it is a useful measure for evaluating the relative monetary significance of our oil and natural gas assets. Further, investors may utilize the measure as a basis for comparison of the relative size and value of our reserves to other companies. We use this measure when assessing the potential return on investment related to our oil and natural gas assets. PV-10, however, is not a substitute for the standardized measure of discounted future net cash flows. Our PV-10 measure and the standardized measure of discounted future net cash flows do not purport to present the fair value of our oil and natural gas reserves.
The following table provides a reconciliation of the GAAP standardized measure of discounted future net cash flows to PV-10 (non-GAAP) at December 31, 2019, 2018 and 2017:
(in millions)
December 31,
2019
 
2018
 
2017
Standardized measure of discounted future net cash flows
$
9,583

 
$
15,555

 
$
7,478

Present value of future income taxes discounted at 10%
1,000

 
2,392

 
1,001

PV-10
$
10,583

 
$
17,947

 
$
8,479

 
 
 
 
 
 

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Reconciliation of Net Income (Loss) to Adjusted EBITDAX
Adjusted EBITDAX (as defined below) is presented herein and reconciled from the GAAP measure of net income (loss) because of its wide acceptance by the investment community as a financial indicator.
We define adjusted EBITDAX as net income (loss), plus (1) exploration and abandonments, (2) depreciation, depletion and amortization, (3) accretion of discount on asset retirement obligations, (4) impairments of long-lived assets, (5) impairments of goodwill, (6) non-cash stock-based compensation, (7) (gain) loss on derivatives, (8) net cash receipts from (payments on) derivatives, (9) (gain) loss on disposition of assets and other, (10) interest expense, (11) loss on extinguishment of debt, (12) gain on equity method investments, (13) RSP transaction costs and (14) income tax expense (benefit). Adjusted EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.
Our adjusted EBITDAX measure provides additional information that may be used to better understand our operations. Adjusted EBITDAX is one of several metrics that we use as a supplemental financial measurement in the evaluation of our business and should not be considered as an alternative to, or more meaningful than, net income (loss) as an indicator of operating performance. Certain items excluded from adjusted EBITDAX are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure, as well as the historic cost of depreciable and depletable assets. Adjusted EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that adjusted EBITDAX is a widely followed measure of operating performance and is one of many metrics used by our management team and by other users of our consolidated financial statements. For example, adjusted EBITDAX can be used to assess our operating performance and return on capital in comparison to other independent exploration and production companies without regard to financial or capital structure, and to assess the financial performance of our assets and our Company without regard to capital structure or historical cost basis. Adjusted EBITDAX, as used herein, may not be comparable to similarly titled measures reported by other companies.
The following table provides a reconciliation of the GAAP measure of net income (loss) to adjusted EBITDAX (non-GAAP) for the periods indicated:
(in millions)
Years Ended December 31,
2019
 
2018
 
2017
 
2016
 
2015
Net income (loss)
$
(705
)
 
$
2,286

 
$
956

 
$
(1,462
)
 
$
66

Exploration and abandonments
201

 
65

 
59

 
77

 
59

Depreciation, depletion and amortization
1,964

 
1,478

 
1,146

 
1,167

 
1,223

Accretion of discount on asset retirement obligations
10

 
10

 
8

 
7

 
8

Impairments of long-lived assets
890

 

 

 
1,525

 
61

Impairments of goodwill
282

 

 

 

 

Non-cash stock-based compensation
85

 
82

 
60

 
59

 
63

(Gain) loss on derivatives
895

 
(832
)
 
126

 
369

 
(700
)
Net cash receipts from (payments on) derivatives
(98
)
 
(218
)
 
79

 
625

 
633

(Gain) loss on disposition of assets and other
(456
)
 
(800
)
 
(678
)
 
(118
)
 
54

Interest expense
185

 
149

 
146

 
204

 
215

Loss on extinguishment of debt

 

 
66

 
56

 

Gain on equity method investments
(17
)
 
(103
)
 

 

 

RSP transaction costs

 
32

 

 

 

Income tax expense (benefit)
(154
)
 
603

 
(75
)
 
(876
)
 
31

Adjusted EBITDAX
$
3,082

 
$
2,752

 
$
1,893

 
$
1,633

 
$
1,713

 
 
 
 
 
 
 
 
 
 

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Item 1A.  Risk Factors
You should consider carefully the following risk factors together with all of the other information included in this report and other reports filed with the SEC before investing in our securities. If any of the following risks were actually to occur, our business, financial condition or results of operations could be materially adversely affected. In that case, the trading price of our securities could decline and you could lose all or part of your investment.
Risks Related to Our Business
Oil and natural gas prices are volatile. A decline in oil and natural gas prices could adversely affect our financial position, financial results, cash flow, access to capital and ability to grow.
Our future financial condition, revenues, results of operations, rate of growth and the carrying value of our oil and natural gas properties depend primarily upon the prices we receive for our oil and natural gas production and the prices prevailing from time to time for oil and natural gas. Oil and natural gas prices historically have been volatile and are likely to continue to be volatile in the future, especially given current geopolitical conditions. This price volatility also affects the amount of cash flow we have available for capital expenditures and our ability to borrow money or raise additional capital. The prices and levels of production for oil and natural gas are subject to a variety of factors beyond our control, including:
the overall global demand for oil and natural gas;
the overall global supply of oil and natural gas;
the overall North American oil and natural gas supply and demand fundamentals, including:
the U.S. economy,
weather conditions, and
liquefied natural gas (“LNG”) deliveries to and exports from the United States;
the proximity, capacity, cost and availability of pipelines and other transportation facilities, as well as the availability of commodity processing and gathering and refining capacity;
risks related to the concentration of our operations in the Permian Basin of West Texas and Southeast New Mexico and the level of commodity inventory in the Permian Basin;
economic conditions worldwide, including adverse conditions driven by political, health or weather events;
the level of global crude oil, crude oil products and LNG inventories;
volatility and trading patterns in the commodity-futures markets;
political and economic developments in oil and natural gas producing regions, including Africa, South America and the Middle East;
the extent to which members of the Organization of Petroleum Exporting Countries and other oil exporting nations are able to influence global oil supply levels;
changes in trade relations and policies, including the imposition of tariffs by the United States or China;
technological advances or social attitudes and policies affecting energy consumption and sources of energy supply;
activism or activities by non-governmental organizations to limit certain sources of capital for the energy sector or restrict the exploration, development and production of oil and gas;
the effect of energy conservation efforts, alternative fuel requirements and climate change-related initiatives;
additional restrictions on the exploration, development and production of oil, natural gas and natural gas liquids so as to materially reduce emissions of carbon dioxide and methane GHGs;
political and economic events that directly or indirectly impact the relative strength or weakness of the U.S. dollar, on which oil prices are benchmarked globally, against foreign currencies;
domestic and foreign governmental regulations, including limits on the United States’ ability to export crude oil, and taxation;

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the cost and availability of products and personnel needed for us to produce oil and natural gas, including rigs, crews, sand, water and water disposal;
the quality of the oil we produce; and
the price, availability and acceptance of alternative fuels.
Furthermore, oil and natural gas prices continued to be volatile in 2019. For example, NYMEX oil prices in 2019 ranged from a high of $66.30 to a low of $45.41 per Bbl and the NYMEX natural gas prices in 2019 ranged from a high of $3.59 to a low of $2.07 per MMBtu.
Declines in oil and natural gas prices would not only reduce our revenue, but could also reduce the amount of oil and natural gas that we can produce economically. This in turn would lower the amount of oil and natural gas reserves we could recognize and, as a result, could have a material adverse effect on our financial condition and results of operations. If the oil and natural gas industry experiences significant price declines for a sustained period, we may, among other things, be unable to maintain or increase our borrowing capacity, repay current or future indebtedness or obtain additional capital on attractive terms, all of which can adversely affect the value of our securities.
Approximately 26 percent of our total estimated proved reserves at December 31, 2019 were undeveloped, and those reserves may not ultimately be developed.
At December 31, 2019, approximately 26 percent of our total estimated proved reserves were undeveloped. Recovery of undeveloped reserves requires significant capital expenditures and successful drilling. Our reserves data assumes that we can and will make these expenditures and conduct these operations successfully. These assumptions, however, may not prove correct. Our reserve report at December 31, 2019 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $2.4 billion. If we choose not to spend the capital to develop these reserves, or if we are not otherwise able to successfully develop these reserves, we will be required to write-off these reserves. In addition, under the SEC’s reserve rules, because proved undeveloped reserves may be recognized only if they relate to wells planned to be drilled within five years of the date of their initial recognition, we may be required to write-off any proved undeveloped reserves that are not developed within this five-year time frame. For example, as of December 31, 2019, we wrote-off approximately 28 MMBoe of proved undeveloped reserves primarily because we no longer expect to develop these reserves within five years of the date of their initial recognition.
Drilling for and producing oil and natural gas are high-risk activities with many uncertainties that could cause our costs to increase or production volumes to decrease, which would reduce our cash flows.
Our future financial condition and results of operations depend on the success of our exploration and production activities. Our oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that drilling will not result in commercially viable oil and natural gas production. Our decisions to purchase, explore, develop or otherwise exploit prospects or properties will depend in part on the evaluation of data obtained through geophysical and geological analyses, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Our cost of drilling, completing, equipping and operating wells is often uncertain before drilling commences. Overruns in budgeted expenditures are common risks that can make a particular project uneconomical or less economical than forecasted. Further, many factors may curtail, delay or cancel drilling, including the following:
delays imposed by or resulting from compliance with regulatory and contractual requirements;
reductions in oil and natural gas prices;
delays and costs of drilling wells on lands subject to complex development terms and circumstances;
oil or natural gas gathering, transportation and processing availability restrictions or limitations;
pressure or irregularities in geological formations;
equipment failures or accidents;
adverse weather conditions and natural disasters;
environmental hazards, such as natural gas leaks, hydrogen sulfide (“H2S”) treating capacity constraints, oil and produced water spills, pipeline and tank ruptures, encountering naturally occurring radioactive materials, and unauthorized discharges of brine, well stimulation and completion fluids, toxic gases or other pollutants into the surface and subsurface environment;
surface access restrictions;

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failure to obtain regulatory and third-party approvals;
actions by third-party operators of our properties, including offsetting fracturing stimulation operations;
political events, public protests, civil disturbances, terrorist acts or cyber attacks;
shortages of or delays in obtaining equipment and qualified personnel or in obtaining sand or water for hydraulic fracturing activities;
loss of title or other title related issues;
limitations in the market for oil and natural gas; and
limited availability of financing at acceptable terms.
The occurrence of one or more of these factors could result in a partial or total loss of our investment in a particular property, as well as significant liabilities. Moreover, certain of these events could result in environmental pollution and impact to third parties, including persons living in proximity to our operations, our employees and employees of our contractors, leading to possible injuries, death or significant damage to property and natural resources.
In addition, the results of our exploratory drilling, including well spacing tests, in new or emerging plays are more uncertain than drilling results in areas that are developed and have established production. Since new or emerging plays and new formations have limited or no production history, we are unable to use past drilling results in those areas to help predict our future drilling results. As a result, our cost of drilling, completing and operating wells in these areas may be higher than initially expected, and the value of our undeveloped acreage will decline if drilling results are unsuccessful.
Multi-well pad drilling and project development may result in volatility in our operating results.
We utilize multi-well pad drilling and project development where practical. Project development may involve more than one multi-well pad being drilled and completed at one time in a relatively confined area. Wells drilled on a pad or in a project may not be brought into production until all wells on the pad or project are drilled and completed. Problems affecting one pad or a single well could adversely affect production from all of the wells on the pad or in the entire project. As a result, multi-well pad drilling and project development can cause delays in the scheduled commencement of production, or interruptions in ongoing production. These delays or interruptions may cause declines or volatility in our operating results due to timing as well as declines in oil and natural gas prices. Further, any delay, reduction or curtailment of our development and producing operations, due to operational delays caused by multi-well pad drilling or project development, or otherwise, could result in the loss of acreage through lease expirations.
Additionally, infrastructure expansion, including more complex facilities and takeaway capacity, could become challenging in project development areas. Managing capital expenditures for infrastructure expansion could cause economic constraints when considering design capacity.
We could experience adverse impacts associated with a high concentration of activity and tighter drilling spacing.
We are subject to drilling, completion and operating risks, including our ability to efficiently execute large-scale project development, as we could experience delays, curtailments and other adverse impacts associated with a high concentration of activity and tighter drilling spacing. A higher concentration of activity and tighter drilling spacing may increase the risk of unintentional communication with other adjacent wells and the potential to reduce total recoverable reserves from the reservoir. If these risks materialize and negatively impact our results of operations relative to guidance or market expectations, and the research analysts who cover our Company may downgrade our common stock or change their recommendations or earnings or performance estimates, which may result in a decline in the market price of our common stock.
Prolonged decreases in our drilling program may require us to pay certain non-use fees or impact our ability to comply with certain contractual requirements. 
In the event that oil prices decline for a sustained period, we may experience significant decreases in drilling activity. Due to the nature of our drilling programs and the oil and natural gas industry in general, we are a party to certain agreements that require us to meet various contractual obligations or require us to utilize a certain amount of goods or services, including, but not limited to, water commitments, throughput volume commitments, power commitments and drilling commitments. In the event that oil and natural gas prices decrease, and as a result continue to reduce the demand for drilling and production, this could lead to a decrease in our drilling activity and production levels, which could, in turn, require us to pay for unutilized goods or services or impact our ability to meet these contractual obligations, including drilling commitments that may result in lease expirations if unmet.
We may incur losses as a result of title defects in our oil and natural gas properties.
It is our practice to initially conduct only a cursory title review of the oil and natural gas properties on which we do not have proved reserves. To the extent title opinions or other investigations prior to our commencement of drilling operations reflect defects

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affecting such properties, we are typically responsible for curing any such defects at our expense. Additionally, the discovery of any such defects could delay or prohibit the commencement of drilling operations on the affected properties. These impacts and other potential losses resulting from title defects in our oil and natural gas properties could have a material adverse effect on our business, financial condition and results of operations.
Our operations are substantially dependent on the availability of water and our ability to dispose of produced water gathered from drilling and production activities. Restrictions on our ability to obtain water or dispose of produced water may have an adverse effect on our financial condition, results of operations and cash flows.
Water is an essential component of both the drilling and hydraulic fracturing processes. West Texas and Southeast New Mexico have experienced extreme drought conditions in the past and we cannot guarantee what conditions may occur in the future. Severe drought conditions can result in local water districts taking steps to restrict the use of water subject to their jurisdiction for drilling and hydraulic fracturing in order to protect the local water supply. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. If we are unable to obtain water to use in our operations from local sources, we may be unable to economically produce oil and natural gas, which could have an adverse effect on our financial condition, results of operations and cash flows.
In addition, we must dispose of the fluids produced from oil and natural gas production operations, including produced water, which we do directly or through the use of third-party vendors. The legal requirements related to the disposal of produced water into a non-producing geologic formation by means of underground injection wells are subject to change based on concerns of the public or governmental authorities regarding such disposal activities. One such concern arises from recent seismic events near underground disposal wells that are used for the disposal by injection of produced water resulting from oil and natural gas activities. In March 2016, the United States Geological Survey identified Texas and Colorado as being among the states with areas of increased rates of induced seismicity that could be attributed to fluid injection or oil and natural gas extraction. In response to concerns regarding induced seismicity, regulators in some states have imposed, or are considering imposing, additional requirements in the permitting of produced water disposal wells to assess any relationship between seismicity and the use of such wells. For example, in Texas, the RRC adopted new rules governing the permitting or re-permitting of wells used to dispose of produced water and other fluids resulting from the production of oil and natural gas in order to address these seismic activity concerns within the state. Among other things, these rules require companies seeking permits for disposal wells to provide seismic activity data in permit applications, provide for more frequent monitoring and reporting for certain wells and allow the state to modify, suspend or terminate permits on grounds that a disposal well is likely to be, or determined to be, causing seismic activity. States may issue orders to temporarily shut down or to curtail the injection depth of existing wells in the vicinity of seismic events.
Another consequence of seismic events may be lawsuits alleging that disposal well operations have caused damage to neighboring properties or otherwise violated state and federal rules regulating waste disposal. These developments could result in additional regulation and restrictions on the use of injection wells by us or by commercial disposal well vendors whom we may use from time to time to dispose of produced water. Increased regulation and attention given to induced seismicity could also lead to greater opposition, including litigation to limit or prohibit oil and natural gas activities utilizing injection wells for produced water disposal.
Any one or more of these developments may result in us or our vendors having to limit disposal well volumes, disposal rates and pressures or locations, or require us or our vendors to shut down or curtail the injection into disposal wells, which events could have a material adverse effect on our business, financial condition and results of operations.
Federal, state and local legislation and regulatory initiatives relating to hydraulic fracturing, as well as governmental reviews of such activities, could result in increased costs and additional operating restrictions or delays and adversely affect our production.
Hydraulic fracturing is an important and common practice that is used to stimulate production of hydrocarbons from tight formations. We routinely utilize hydraulic fracturing techniques in many of our drilling and completion programs. The process involves the injection of water, sand and chemicals under pressure into the formation to fracture the surrounding rock and stimulate production. The process is typically regulated by state oil and natural gas commissions. However, the EPA recently asserted federal regulatory authority over hydraulic fracturing involving diesel additives under the SDWA’s Underground Injection Control Program and issued guidance in February 2014, governing such activities. The EPA has also issued: final regulations under the CAA establishing performance standards, including standards for the capture of VOCs and methane released during hydraulic fracturing (although the EPA has temporarily suspended or delayed compliance with certain of these standards as they undergo an administrative review); an advanced notice of proposed rulemaking under the Toxic Substances Control Act to require companies to disclose information regarding the chemicals used in hydraulic fracturing; and final rules in June 2016 to prohibit the discharge of wastewater from hydraulic fracturing operations to publicly owned wastewater treatment plants. Moreover, in March 2015, the BLM issued a final rule that imposes requirements on hydraulic fracturing activities on federal and Indian lands, including new requirements relating to public disclosure, wellbore integrity and handling of flowback water. However, the BLM lacked authority to promulgate the rule. While that decision was on appeal, the BLM rescinded this rule in December 2017. In January 2018, the state of California and a coalition of environmental groups filed a lawsuit in the Northern District of California to challenge the BLM’s rescission of the 2015 rule. This litigation is ongoing and future implementation of the rule is uncertain at this time.

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At the state level, several states have adopted or are considering legal requirements that could impose more stringent permitting, disclosure, and well construction requirements on hydraulic fracturing activities. For example, New Mexico and Texas have adopted hydraulic fracturing fluid disclosure requirements, and the RRC has also adopted rules governing well casing, cementing and other standards for ensuring that hydraulic fracturing operations do not contaminate nearby water resources. In addition, local governments have also taken steps to regulate hydraulic fracturing, including imposing restrictions or moratoria on oil and natural gas activities occurring within their boundaries. If new or more stringent federal, state, or local legal restrictions relating to the hydraulic fracturing process are adopted in areas where we operate, we could incur potentially significant added costs to comply with such requirements, experience delays or curtailment in the pursuit of exploration, development, or production activities, and perhaps even be precluded from drilling wells.
In addition, certain governmental reviews are either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. For example, in December 2016, the EPA released its final report on the potential impacts of hydraulic fracturing on drinking water resources. The final report concluded that “water cycle” activities associated with hydraulic fracturing may impact drinking water resources under some circumstances, noting that the following hydraulic fracturing water cycle activities and local- or regional-scale factors are more likely than others to result in more frequent or more severe impacts: 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. Since the report did not find a direct link between hydraulic fracturing itself and contamination of groundwater resources, this years-long study report does not appear to provide any basis for further regulation of hydraulic fracturing at the federal level.
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. In addition, if hydraulic fracturing becomes regulated at the federal level as a result of federal legislation or regulatory initiatives by the EPA, our fracturing activities could become subject to additional permitting requirements and could also result in permitting delays and potential cost increases. Restrictions on hydraulic fracturing could also reduce the amount of oil and natural gas that we are ultimately able to produce from our reserves.
Climate change legislation, regulations restricting emissions of “greenhouse gases” or legal or other action taken by public or private entities related to climate change could result in increased operating costs and reduced demand for the oil and natural gas that we produce.
In response to findings that emissions of carbon dioxide, methane and other greenhouse gases present an endangerment to public health and the environment, the EPA has issued regulations to restrict emissions of GHGs under existing provisions of the CAA. These regulations include limits on tailpipe emissions from motor vehicles and preconstruction and operating permit requirements for certain large stationary sources. The EPA has also adopted rules requiring the reporting of GHG emissions from specified large GHG emission sources in the United States, as well as certain onshore oil and natural gas production facilities, on an annual basis, including GHG emissions resulting from the completion and workover operations of hydraulically fractured oil wells. Recent federal regulatory action with respect to climate change has focused on methane emissions. These methane emission rules have the potential to increase our compliance costs. See “Item 1. Business—Applicable Laws and Regulations—Environmental, Health and Safety Matters” for additional information.
While Congress has from time to time considered legislation to reduce emissions of GHGs, there has not been significant activity in the form of adopted legislation to reduce emissions of GHGs in recent years. In the absence of Congressional action, many states have established rules aimed at reducing GHG emissions, including GHG cap and trade programs. Most of these cap and trade programs work by requiring major sources of emissions, such as electric power plants, or major producers of fuels, such as refineries and natural gas processing plants, to acquire and surrender emission allowances. The number of allowances available for purchase is reduced each year in an effort to achieve the overall GHG emission reduction goal. In the future, the United States may also choose to adhere to international agreements targeting GHG reductions.
The adoption of legislation or regulatory programs to reduce emissions of GHGs could require us to incur increased operating costs, such as costs to purchase and operate emissions control systems, to acquire emissions allowances or to comply with new regulatory or reporting requirements. Any such legislation or regulatory programs could also 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. Reduced demand for the oil and natural gas that we produce could also have the effect of lowering the value of our reserves. It should also be noted that some scientists have concluded that increasing concentrations of GHGs in the earth’s atmosphere may produce climate changes that have significant physical effects, such as increased frequency and severity of storms, droughts, and floods and other climatic events. If any such effects were to occur, they could have an adverse effect on our financial condition and results of operations. In addition, there have also been efforts in recent years to influence the investment community, including investment advisors and certain sovereign wealth, pension and endowment funds promoting divestment of fossil fuel equities and pressuring lenders to limit funding to companies engaged in the extraction of fossil fuel reserves. Such environmental activism and initiatives aimed at limiting climate change and reducing air pollution could interfere with our business activities, operations and ability to access capital. Finally, increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits or investigations brought by public and private entities against oil and natural gas companies in connection with their GHG emissions. Should we be targeted by any such litigation or investigations, we may incur liability, which, to the extent that societal pressures or political or other factors

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are involved, could be imposed without regard to the causation of or contribution to the asserted damage, or to other mitigating factors. The ultimate impact of GHG emissions-related agreements, legislation and measures on our company’s financial performance is highly uncertain because the Company is unable to predict with certainty, for a multitude of individual jurisdictions, the outcome of political decision-making processes and the variables and tradeoffs that inevitably occur in connection with such processes.
Estimates of proved reserves and future net cash flows are not precise. The actual quantities of our proved reserves and our future net cash flows may prove to be lower than estimated.
Numerous uncertainties exist in estimating quantities of proved reserves and future net cash flows therefrom. Our estimates of proved reserves and related future net cash flows are based on various assumptions, which may ultimately prove to be inaccurate.
Petroleum engineering is a subjective process of estimating accumulations of oil and natural gas that cannot be measured in an exact manner. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including the following:
historical production from the area compared with production from other producing areas;
the assumed effects of regulations by governmental agencies;
the quality, quantity and interpretation of available relevant data;
assumptions concerning future commodity prices; and
assumptions concerning future operating costs, severance, excise and ad valorem taxes, development costs, gathering, processing and transportation costs and workover and remedial costs.
Because all reserve estimates are to some degree subjective, each of the following items, or other items not identified below, may differ materially from those assumed in estimating reserves:
the quantities of oil and natural gas that are ultimately recovered;
the production and operating costs incurred;
the amount and timing of future development expenditures; and
future commodity prices.
Furthermore, different reserve engineers may make different estimates of reserves and cash flows based on the same data, and improvements or other changes in geological, geophysical and engineering evaluation methods may cause reserve estimates to change over time. Our actual production, revenues and expenditures with respect to reserves will likely be different from estimates and the differences may be material.
As required by the SEC, the estimated discounted future net cash flows from proved reserves are based on the average previous twelve months first-of-month prices preceding the date of the estimate and costs as of the date of the estimate, while actual future prices and costs may be materially higher or lower. Actual future net cash flows also will be affected by factors such as:
the amount and timing of actual production;
levels of future capital spending;
increases or decreases in the supply of or demand for oil and natural gas; and
changes in governmental regulations or taxation.
Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. Therefore, the estimates of discounted future net cash flows in this report should not be construed as accurate estimates of the current market value of our proved reserves.
Our business requires substantial capital expenditures. We may be unable to obtain needed capital or financing on satisfactory terms or at all, which could lead to a decline in our oil and natural gas reserves.
The oil and natural gas industry is capital intensive. We make and expect to continue to make substantial capital expenditures for the acquisition, exploration and development of oil and natural gas reserves. At December 31, 2019, we did not have any debt outstanding under our Credit Facility (and total debt at December 31, 2019 of $4.0 billion), and we had approximately $2.0 billion of unused commitments under our Credit Facility. Expenditures for acquisition, exploration and development of oil and natural gas properties are the primary use of our capital resources. We incurred approximately $3.1 billion in acquisition, exploration and

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development costs during the year ended December 31, 2019. In February 2020, our board of directors approved our 2020 capital budget of up to $2.9 billion. We expect to spend between $2.6 billion and $2.8 billion on drilling and completion activity. We plan to spend approximately $2.4 billion over the next five years on future development costs associated with proved undeveloped reserves.
We intend to finance our future capital expenditures, other than significant acquisitions, through cash flow from operations and, if necessary, through borrowings under our Credit Facility. However, our cash flow from operations and access to capital are subject to a number of variables, including:
the volume of oil and natural gas we are able to produce from existing wells;
our ability to transport our oil and natural gas to market;
the prices at which our commodities are sold;
the costs of producing oil and natural gas;
global credit and securities markets;
the ability and willingness of lenders and investors to provide capital and the cost of the capital;
our ability to acquire, locate and produce new reserves; and
the impact of potential changes in our credit ratings.
We may not generate expected cash flows and may have limited ability to obtain the capital necessary to sustain our operations at current or anticipated levels. A decline in cash flow from operations or our financing needs may require us to revise our capital program or alter or increase our capitalization substantially through the issuance of debt or equity securities. The issuance of additional equity securities could have a dilutive effect on the value of our common stock. Additional borrowings under our Credit Facility or the issuance of additional debt securities will require that a greater portion of our cash flow from operations be used for the payment of interest and principal on our debt, thereby reducing our ability to use cash flow to fund working capital, capital expenditures and acquisitions. In addition, our Credit Facility imposes certain limitations on our ability to incur additional indebtedness other than indebtedness under our Credit Facility. If we desire to issue additional debt securities other than as expressly permitted under our Credit Facility, we will be required to seek the consent of the lenders in accordance with the requirements of our Credit Facility, which consent may be withheld by the lenders at their discretion. Additional financing also may not be available on acceptable terms or at all. In the event additional capital resources are unavailable, we may curtail drilling, development and other activities or be forced to sell some of our assets on an untimely or unfavorable basis.
The failure to obtain additional financing could result in a curtailment of our operations relating to the development of our undeveloped acreage or the curtailment of acquisitions that may be favorable to us, which in turn could lead to a decline in our oil and natural gas reserves, and could adversely affect our production, revenues and results of operations.
A decline in general economic, business or industry conditions could have a material adverse effect on our results of operations.
A global economic downturn, particularly with respect to the U.S. economy or the oil and natural gas industry, and global financial and credit market disruptions reduce the availability of liquidity and credit to fund the continuation and expansion of industrial business operations worldwide, which can result in a slowdown in economic activity. Reduced worldwide demand for energy often results in lower commodity prices, which will reduce our cash flows and may affect our borrowing ability. If the economic climate in the United States or abroad deteriorates, we may be unable to obtain needed capital or financing on satisfactory terms, which could lead to a decline in our reserves as existing reserves are depleted. Lower commodity prices may also reduce the amount of oil and natural gas that we can produce economically, which could ultimately decrease our net revenue and profitability. In addition, reduced worldwide demand for securities issued by oil and natural gas companies or depressed trading prices of the debt and equity securities of oil and natural gas companies generally may depress the market value of our securities or make it more difficult for us to raise capital.
Certain federal income tax deductions currently available with respect to oil and natural gas exploration and development may be eliminated. Additional state taxes on oil and natural gas extraction may be imposed, as a result of future legislation.
In recent years, U.S. lawmakers have proposed certain significant changes to U.S. tax laws applicable to oil and natural gas companies. These changes include, but are not limited to: (i) the elimination of current deductions for intangible drilling and development costs; (ii) the repeal of the percentage depletion allowance for oil and natural gas properties; and (iii) an extension of the amortization period for certain geological and geophysical expenditures. Although these changes were not included in the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“TCJA”), it is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes (or the imposition of, or increases in, production, severance or similar taxes) were to be enacted, as well as any similar changes in state, local or non-U.S. law, it could

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eliminate or postpone certain tax deductions that are currently available to us with respect to oil and natural gas exploration and development, and any such change could negatively affect our financial condition and results of operations.
Additionally, future legislation could be enacted that increases the taxes or fees imposed on oil and natural gas extraction. Any such legislation could result in increased operating costs and/or reduced consumer demand for petroleum products, which in turn could affect the prices we receive for our oil and natural gas.
Our ability to use our existing net operating loss carryforwards or other tax attributes could be limited.
At December 31, 2019, we had approximately $2.6 billion of federal net operating loss (“NOL”) carryforwards available to offset against future taxable income. Of these NOL carryforwards, $1.5 billion were generated prior to the effective date of new limitations on utilization of NOLs imposed by the TCJA and are allowable as a deduction against 100 percent of taxable income in future years but will begin to expire in the tax year 2034. The remaining federal NOL of $1.1 billion is subject to an 80 percent limitation but has an indefinite carryforward life. Included in our $2.6 billion of federal NOL carryforwards is approximately $516 million net NOLs that we acquired as part of the RSP Acquisition. This acquired tax NOL, $40 million of research and development (“R&D”) credits and $38 million of interest expense limitation carryforwards (“tax attributes”) are subject to an annual limitation under Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”). However, based on the annual limitation amount, our acquired tax attributes are considered more likely than not to be utilized.
Utilization of any tax attribute depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 generally imposes an annual limitation on the amount of tax attributes that may be used to offset taxable income and tax liability when a corporation has undergone an “ownership change” (as determined under Section 382). An ownership change generally occurs if one or more stockholders (or groups of stockholders) who are each deemed to own at least five percent of our stock change their ownership by more than 50 percentage points over their lowest ownership percentage within a rolling three-year period. In the event that an ownership change has occurred, or were to occur, utilization of all of our tax attributes, including those acquired from RSP, would be subject to an annual limitation under Section 382, determined by multiplying the value of our equity at the time of the ownership change by the applicable long-term tax-exempt rate as defined in Section 382, and potentially increased for certain gains recognized within five years after the ownership change if we have a net built-in gain in our assets at the time of the ownership change. Any unused annual limitation may be carried over to later years. We do not believe that an ownership change has occurred as a result of our equity offerings or our issuance of shares in connection with various acquisitions. As such, Section 382 is not expected to limit our ability to utilize our NOL carryforward or any other tax attributes at December 31, 2019. Future ownership changes or future regulatory changes could limit our ability to utilize our tax attributes. To the extent we are not able to offset our future income with our NOLs or tax liability with tax credits, this could adversely affect our operating results and cash flows once we attain profitability.
We have substantial indebtedness and may incur substantially more debt. Higher levels of indebtedness make us more vulnerable to economic downturns and adverse developments in our business.
We had approximately $4.0 billion of outstanding aggregate principal indebtedness at December 31, 2019. At December 31, 2019, commitments from our bank group were $2.0 billion, all of which was unused. We continue to review our existing indebtedness, and we may seek to repay, refinance, repurchase, redeem, exchange or otherwise terminate our indebtedness. If we do seek to refinance our existing indebtedness, there can be no guarantee that we would be able to execute the refinancing on favorable terms or at all.
As a result of our indebtedness, we use a portion of our cash flow to pay interest, which reduces the amount we have available to fund our operations and other business activities and could limit our flexibility in planning for or reacting to changes in our business and the industry in which we operate. Our indebtedness under our Credit Facility is at a variable interest rate, and so a rise in interest rates will generate greater interest expense. Financial regulators are working to transition away from LIBOR as a reference rate for financial contracts by the end of 2021 and to develop benchmarks to replace LIBOR. Certain types of borrowings under our Credit Facility are derived from the LIBOR reference rate. Our Credit Facility agreement includes general provisions governing the establishment of an alternate rate of interest to the LIBOR-based rate that gives consideration to the then prevailing market convention for determining a rate of interest for comparable syndicated loans. At this time, the impact on the Company's borrowing costs, if any, under an alternative reference rate scenario is uncertain.
We may incur substantially more debt in the future. Our Credit Facility and the indentures governing our senior notes contain restrictions on our incurrence of additional indebtedness. These restrictions, however, are subject to a number of qualifications and exceptions, and under certain circumstances, we could incur substantial additional indebtedness in compliance with these restrictions. Moreover, these restrictions do not prevent us from incurring obligations that do not constitute indebtedness under the indentures.
Any increase in our level of indebtedness could have adverse effects on our financial condition and results of operations, including:
imposing additional cash requirements on us in order to support interest payments, which reduces the amount we have available to fund our operations and other business activities;

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increasing the risk that we may default on our debt obligations;
increasing our vulnerability to adverse changes in general economic and industry conditions, economic downturns and adverse developments in our business;
limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes;
limiting our flexibility in planning for or reacting to changes in our business and the industry in which we operate; and
increasing our exposure to a rise in interest rates, which will generate greater interest expense.
Our ability to meet our debt obligations and to reduce our level of indebtedness depends on our future performance, which is affected by general economic conditions and financial, business and other factors, many of which are out of our control.
If we are unable to comply with the restrictions and covenants in the agreements governing our indebtedness, there could be a default under the terms of these agreements, which could result in an acceleration of payment of funds that we have borrowed.
Our ability to meet our debt obligations and other expenses will depend on our future performance, which will be affected by financial, business, economic, regulatory and other factors, many of which we are unable to control. If our cash flow is not sufficient to service our debt, we may be required to refinance debt, sell assets or sell additional equity on terms that we may not find attractive if it may be done at all. If we are unable to generate sufficient cash flow and are otherwise unable to obtain funds necessary to meet required payments of principal, premium, if any, and interest, if any, on our indebtedness, or if we otherwise fail to comply with the various covenants, including financial and operating covenants, in the agreements governing our indebtedness, we could be in default under the terms of the agreements governing such indebtedness. In the event of such default:
the holders of such indebtedness could elect to declare all the funds borrowed thereunder to be due and payable, together with accrued and unpaid interest;
the lenders under our Credit Facility could elect to terminate their commitments thereunder and cease making further loans; and
we could be forced into bankruptcy or liquidation.
If our operating performance declines, we may in the future need to obtain waivers under our Credit Facility to avoid being in default. If we breach our covenants under our Credit Facility and cannot obtain a waiver from the required lenders, we would be in default under our Credit Facility, the lenders could exercise their rights, as described above, and we could be forced into bankruptcy or liquidation.
A downgrade in our credit rating could negatively impact our cost of and ability to access capital.
We receive debt credit ratings from S&P Global Ratings (“S&P”), Moody’s Investors Service, Inc. (“Moody’s”) and Fitch Ratings (“Fitch”), which are subject to regular reviews. In determining our ratings, the agencies consider a number of qualitative and quantitative factors including, but not limited to: the industry in which we operate, production growth opportunities, liquidity, debt levels and asset and reserve mix.
A downgrade in our credit ratings could (i) negatively impact our costs of capital and our ability to effectively execute aspects of our strategy, (ii) affect our ability to raise debt in the public debt markets, and the cost of any new debt could be much higher than our outstanding debt and (iii) negatively affect our ability to obtain additional financing or the interest rate, fees and other terms associated with such additional financing. In September 2017, we elected to enter into an Investment Grade Period under our Credit Facility, as defined in Note 10 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data,” which had the effect of releasing all collateral formerly securing our Credit Facility. If we are unable to maintain credit ratings of “Ba2” or better from Moody’s and “BB” or better from S&P, the Investment Grade Period will automatically terminate and cause our Credit Facility to once again be secured by a first lien on substantially all of our oil and natural gas properties and by a pledge of the equity interests in our subsidiaries. These and other impacts of a downgrade in our credit ratings could have a material adverse effect on our business, financial condition and results of operations.
As of the filing of this report, no additional changes in our credit ratings have occurred; however, we cannot be assured that our credit ratings will not be downgraded in the future.
Our operations expose us to significant costs and liabilities with respect to environmental and operational safety matters.
We may incur significant delays, costs and liabilities as a result of environmental, occupational health and safety requirements applicable to our oil and natural gas exploration, development and production, and related saltwater disposal activities or the activities

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of our suppliers of critical materials and services. These delays, costs and liabilities could arise under a wide range of federal, state and local laws and regulations relating to protection of the environment (including wildlife and natural resources), occupational health and safety, including regulations and enforcement policies that have tended to become increasingly strict over time. Failure to comply with these laws and regulations may result in the assessment of administrative, civil and criminal penalties, imposition of cleanup and site restoration costs and liens, and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations.
Strict as well as joint and several liability for a variety of environmental costs may be imposed on us under certain environmental laws, which could cause us to become liable for the conduct of others or for consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. Costs stemming from environmental remediation obligations could be significant and adversely affect our financial condition and results of operations. New laws, regulations or enforcement policies could be more stringent and impose unforeseen liabilities or significantly increase compliance costs. No assurance can be given that continued compliance with existing or future environmental laws and regulations will not result in a curtailment of production or processing activities or result in a material increase in the costs of production, development, exploration or processing operations. If we are not able to recover the resulting costs through insurance or increased revenues, our production, revenues and results of operations could be adversely affected.
Our producing properties are concentrated in the Permian Basin of West Texas and Southeast New Mexico, making us vulnerable to risks associated with operating in one major geographic area. In addition, substantially all of our proved reserves are attributable to this area.
Our producing properties are geographically concentrated in the Permian Basin of West Texas and Southeast New Mexico. At December 31, 2019, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this geographic concentration, we are exposed to the impact of regional supply and demand factors; delays or interruptions of production from wells in this area caused by governmental regulation; processing or transportation capacity constraints, including potential pipeline capacity constraints in the Permian Basin; market limitations; severe weather events; water shortages or other drought related conditions; or interruption of the processing or transportation of oil or natural gas.
In addition to the geographic concentration of our producing properties described above, at December 31, 2019, approximately: (i) 55 percent of our proved reserves were attributable to the Delaware Basin that primarily targets the Avalon, Bone Spring and Wolfcamp formations; and (iii) 45 percent of our proved reserves were attributable to the Midland Basin that primarily targets the Spraberry and Wolfcamp formations. This concentration of assets exposes us to additional risks, such as changes in field-wide rules and regulations that could cause us to permanently or temporarily shut-in all of our wells within a field.
We periodically assess our unproved oil and natural gas properties for impairment and could be required to recognize non-cash charges to earnings of future periods.
At December 31, 2019, we carried unproved property costs of $5.9 billion. GAAP requires periodic assessment of these costs on a project-by-project basis. Our assessment considers:
future drilling and exploration plans;
results of exploration activities;
commodity price outlooks;
planned future sales; and
expiration of all or a portion of the projects, contracts and permits relevant to such projects.
Based on our assessments, we may determine that we are unable to fully recover the cost invested in each project, and we will recognize non-cash charges to earnings in future periods if such determination is made. For the years ended December 31, 2019 and 2018, we recorded $147 million and $35 million, respectively, of leasehold abandonments primarily related to expiring acreage and acreage where we had no future plans to drill, which is included in exploration and abandonments expense in our consolidated statements of operations.
We periodically evaluate our goodwill for impairment and could be required to recognize non-cash charges to earnings of future periods.
At December 31, 2019, we had goodwill of approximately $1.9 billion. We assess goodwill for impairment as of July 1 of each year or whenever circumstances indicate that the carrying value of our business may be impaired. If the book value of our reporting unit exceeds the estimated fair value of the reporting unit, an impairment charge will occur, which would negatively impact our results of operations and net worth. We performed an impairment test at December 31, 2019 due to a decline in our fair value during the second half of 2019 and recorded a $201 million impairment charge. See Note 2 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.

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Future price declines could result in a reduction in the carrying value of our proved oil and natural gas properties, which could adversely affect our results of operations.
Declines in commodity prices may result in our having to make substantial downward adjustments to the value of our estimated proved reserves. If this occurs, or if our estimates of production or economic factors change, accounting rules may require us to write-down, as a non-cash charge to earnings, the carrying value of our proved oil and natural gas properties for impairments. We are required to perform impairment tests on proved assets whenever events or changes in circumstances warrant a review of our proved oil and natural gas properties. To the extent such tests indicate a reduction of the estimated useful life or estimated future cash flows of our oil and natural gas properties, the carrying value may not be recoverable and therefore require a write-down. The primary factors that may affect management’s estimates of future cash flows are (i) commodity futures prices, (ii) increases or decreases in production and capital costs, (iii) future reserve volume adjustments, both positive and negative, to proved reserves and appropriate risk-adjusted probable and possible reserves, (iv) results of future drilling activities and (v) prevailing market rates of income and expenses from integrated assets. We may incur impairment charges in the future, which could materially adversely affect our results of operations in the period incurred. We recorded impairment charges of $890 million in 2019. We did not incur an impairment charge in 2018 or 2017. See Note 8 of the Notes to Consolidated Financial Statements included in “Item 8. Financial Statements and Supplementary Data” for additional information.
Our commodity price risk management program may cause us to forego additional future profits or result in us making cash payments to our counterparties.
To reduce our exposure to changes in the prices of commodities, we have entered into and may in the future enter into additional commodity price risk management arrangements for a portion of our oil and natural gas production. The agreements that we have entered into generally have the effect of providing us with a fixed price for a portion of our expected future oil and natural gas production over a fixed period of time. Commodity price risk management arrangements expose us to the risk of financial loss and may limit our ability to benefit from increases in commodity prices in some circumstances, including the following:
market prices may exceed the prices which we are contracted to receive, resulting in our need to make significant cash payments to our counterparties;
there may be a change in the expected differential between the underlying price in a commodity price risk management agreement and actual prices received; or
the counterparty to a commodity price risk management contract may default on its contractual obligations to us.
Our commodity price risk management activities could have the effect of reducing our net income and the value of our securities. At December 31, 2019, we had a net derivative liability of $102 million. An average increase in the commodity price of $5.00 per barrel of oil and $0.50 per MMBtu of natural gas from the commodity price at December 31, 2019 would have resulted in an increase in our net liability of approximately $451 million. We may continue to incur significant gains or losses in the future from our commodity price risk management activities to the extent market prices increase or decrease and our derivatives contracts remain in place.
Our actual production could differ materially from our forecasts.
From time to time, we provide forecasts of expected quantities of future oil and gas production and other financial and operating results. These forecasts are based on a number of estimates and assumptions. Production forecasts, specifically, are based on assumptions such as:
expectations of production from existing wells and future drilling activity;
the absence of facility or equipment malfunctions;
the absence of adverse weather effects;
expectations of commodity prices, which could experience significant volatility;
expected well costs; and
the assumed effects of regulation by governmental agencies, which could make certain drilling activities or production uneconomical.
Should any of these assumptions prove inaccurate, or should our development plans change, actual production could be materially and adversely affected. Failure to meet operating or financial forecasts and expectations, whether published by us or market participants, could adversely impact the trading price of our common stock.
Our identified inventory of drilling locations and recompletion opportunities are scheduled over several future years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.

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We have identified and scheduled the drilling of certain locations as an estimation of our future multi-year development activities on our existing acreage. These identified locations represent a significant part of our development and growth strategy. Our ability to drill and develop these locations depends on a number of uncertainties, including those described elsewhere in these risk factors. Because of these and other potential uncertainties, we may never drill the potential locations we have identified or produce oil or natural gas from these or any other potential locations. As such, our actual development activities may materially differ from those presently identified, which could adversely affect our production, reserves, revenues and results of operations.
Unless we replace our oil and natural gas reserves, our reserves and production will decline, which would adversely affect our cash flow, our ability to raise capital and the value of our securities.
Unless we conduct successful development and exploration activities or acquire properties containing proved reserves, our proved reserves will decline as those reserves are produced. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flow and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production or replace our declining production with new production. We may not be able to develop, exploit, find or acquire sufficient additional reserves or replace our current and future production.
The Standardized Measure and PV-10 of our estimated reserves are not accurate estimates of the current fair value of our estimated proved oil and natural gas reserves.
Standardized Measure is a reporting convention that provides a common basis for comparing oil and natural gas companies subject to the rules and regulations of the SEC. Our non-GAAP financial measure, PV-10, is a similar reporting convention that we have disclosed in this report. Both measures require the use of operating and development costs prevailing as of the date of computation. Consequently, they will not reflect the prices ordinarily received or that will be received for oil and natural gas production because of varying market conditions, nor may it reflect the actual costs that will be required to produce or develop the oil and natural gas properties. Accordingly, estimates included herein of future net cash flows may be materially different from the future net cash flows that are ultimately received. In addition, the 10 percent discount factor, which is required by the rules and regulations of the SEC to be used in calculating discounted future net cash flows for reporting purposes, may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with our company or the oil and natural gas industry in general. Therefore, Standardized Measure and PV-10 included in this report should not be construed as accurate estimates of the current fair value of our proved reserves.
Our reserve estimates and our computation of future net cash flows at December 31, 2019 are based on SEC pricing of (i) $52.19 per Bbl WTI posted oil price and (ii) $2.58 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property. If average oil prices were $5.00 per barrel lower than the average price we used, our PV-10 at December 31, 2019 would have decreased from $10.6 billion to $9.2 billion. If average natural gas prices were $0.50 per MMBtu lower than the average price we used, our PV-10 at December 31, 2019 would have decreased from $10.6 billion to $10.2 billion. Any adjustments to the estimates of proved reserves or decreases in the price of our commodities may decrease the value of our securities.
We may be unable to make attractive acquisitions or successfully integrate acquired companies or assets, and any inability to do so may disrupt our business and hinder our ability to grow.
One aspect of our business strategy calls for acquisitions of businesses or assets that complement or expand our current business. We may not be able to identify attractive acquisition opportunities, including acreage trades. Even if we do identify attractive candidates, pursuing such acquisitions may be distracting to management and costly to the Company. We may not be able to complete the acquisition of them or do so on commercially acceptable terms.
In addition, our Credit Facility and the indentures governing our senior notes impose certain limitations on our ability to enter into mergers or business combination transactions. Our Credit Facility and the indentures governing our senior notes also limit our ability to incur certain indebtedness, which could indirectly limit our ability to engage in acquisitions of businesses or assets. If we desire to engage in an acquisition that is otherwise prohibited by our Credit Facility or the indentures governing our senior notes, we will be required to seek the consent of our lenders or the holders of the senior notes in accordance with the requirements of our Credit Facility or the indentures, which consent may be withheld by the lenders under our Credit Facility or such holders of senior notes at their sole discretion.
If we acquire another business or assets, we could have difficulty integrating its operations, systems, management and other personnel and technology with our own. These difficulties could disrupt our ongoing business, distract our management and employees, increase our expenses and adversely affect our results of operations. In addition, we may incur additional debt or issue additional equity to pay for any future acquisitions, subject to the limitations described above.
Any acquisition we complete is subject to substantial risks that could adversely affect our business, including the risk that our acquisitions may prove to be worth less than what we paid because of uncertainties in evaluating recoverable reserves and could expose us to potentially significant liabilities.

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We obtained a significant portion of our current reserve base through acquisitions of producing properties and undeveloped acreage. We expect that acquisitions, including acreage trades, will continue to contribute to our future growth. In connection with these and potential future acquisitions, we are often only able to perform limited due diligence. The success of any acquisition involves potential risks, including among other things:
the inability to estimate accurately the costs to develop the reserves, recoverable volumes of reserves, rates of future production and future net cash flows attainable from the reserves;
the assumption of unknown liabilities, including environmental liabilities, and losses or costs for which we are not indemnified or for which the indemnity we receive is inadequate;
the effect on our liquidity or financial leverage of using available cash or debt to finance acquisitions;
the diversion of management’s attention from other business concerns; and
an inability to hire, train or retain qualified personnel to manage and operate our growing business and assets.
Successful acquisitions of oil and natural gas properties require an assessment of a number of factors, including estimates of recoverable reserves, the timing of recovering reserves, exploration potential, future commodity prices, operating costs and potential environmental, regulatory and other liabilities. Such assessments are inexact, and we cannot make these assessments with a high degree of accuracy. In connection with our assessments, we perform a review of the acquired properties that we believe to be generally consistent with industry practices. However, such a review will not reveal all existing or potential problems. In addition, our review may not permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities. We do not inspect every well. Even when we inspect a well, we do not always discover structural, subsurface and environmental problems that may exist or arise.
There may be threatened, contemplated, asserted or other claims against the acquired assets related to environmental, title, regulatory, tax, contract, litigation or other matters of which we are unaware, which could materially and adversely affect our production, revenues and results of operations. We are sometimes able to obtain contractual indemnification for preclosing liabilities, including environmental liabilities, but we generally acquire interests in properties on an “as is” basis with limited remedies for breaches of representations and warranties. In addition, even when we are able to obtain such indemnification from the sellers, these indemnification obligations usually expire over time and expose us to potential unindemnified liabilities, which could materially adversely affect our production, revenues and results of operations.
Shortages of oilfield equipment, services and qualified personnel could delay our drilling program and increase the prices we pay to obtain such equipment, services and personnel.
The demand for qualified and experienced field personnel to drill wells and conduct field operations, geologists, geophysicists, engineers and other professionals in the oil and natural gas industry can fluctuate significantly, often in correlation with commodity prices, causing periodic labor shortages. Historically, there have been shortages of drilling and workover rigs, pipe and other oilfield equipment as demand for rigs and equipment has increased along with the number of wells being drilled. These factors also cause significant increases in costs for equipment, services and personnel. Higher commodity prices generally stimulate demand and result in increased prices for drilling and workover rigs, crews and associated supplies, equipment and services. It is beyond our control and ability to predict whether these conditions will exist in the future and, if so, what their timing and duration will be. These types of shortages or price increases would decrease our profit margin, cash flow and operating results, or restrict our ability to drill the wells and conduct the operations which we currently have planned and budgeted or which we may plan in the future.
Our exploration and development drilling may not result in commercially productive reserves.
Drilling activities are subject to many risks, including the risk that commercially productive reservoirs will not be encountered. New wells that we drill may not be productive, or we may not recover all or any portion of our investment in such wells. The seismic data and other technologies we use do not allow us to know conclusively prior to drilling a well that oil or natural gas is present or may be produced economically. Drilling for oil and natural gas often involves unprofitable results, not only from dry holes but also from wells that are productive but do not produce sufficient net reserves to return a profit at then realized prices after deducting drilling, operating and other costs. The cost of drilling, completing and operating a well is often uncertain, and cost factors can adversely affect the economics of a project.
We may incur substantial losses and be subject to substantial liability claims as a result of our oil and natural gas operations. In addition, we may not be insured for, or our insurance may be inadequate to protect us against, these risks.
We are not insured against all risks. Losses and liabilities arising from uninsured and underinsured events could materially and adversely affect our business, financial condition or results of operations. Our oil and natural gas exploration and production activities, including well stimulation and completion activities such as hydraulic fracturing, are subject to all of the operating risks associated with drilling for and producing oil and natural gas, including the possibility of:

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environmental hazards, such as uncontrollable flows of oil, natural gas, saltwater, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;
mechanical difficulties, such as stuck oilfield drilling and service tools and casing collapse;
blowouts, cratering, fires, explosions and ruptures of pipelines;
personal injuries and death; and
natural disasters.
Any of these risks could adversely affect our ability to conduct operations or result in substantial losses to us as a result of:
damage to and destruction of property and equipment;
damage to natural resources due to underground migration of hydraulic fracturing fluids;
pollution and other environmental damage, including spillage or mishandling of recovered hydraulic fracturing fluids;
regulatory investigations and penalties;
loss of well location, acreage, expected production and related reserves;
suspension or delay of our operations;
substantial liability claims; and
repair and remediation costs.
We may elect not to obtain insurance if we believe that the cost of available insurance is excessive relative to the risks presented. In addition, pollution and environmental risks generally are not fully insurable, and we do not insure for business interruption of the loss of a well. The occurrence of an event that is not covered or not fully covered by insurance could have a material adverse effect on our production, revenues and results of operations.
Competition in the oil and natural gas industry is intense, making it more difficult for us to acquire properties, market oil and natural gas and secure trained personnel.
We operate in a highly competitive environment for acquiring properties, marketing oil and natural gas and securing trained personnel. Some of our competitors possess and employ financial, technical and personnel resources substantially greater than ours, which can be particularly important in the areas in which we operate. Those companies may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources permit. In addition, those companies may be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. The cost and other challenges to attract and retain qualified personnel may increase substantially in the future. Our ability to acquire additional prospects and to find and develop reserves in the future will depend on our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment. Also, there is substantial competition for capital available for investment in the oil and natural gas industry. We may not be able to compete successfully in the future in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel and raising additional capital. Our failure to acquire properties, market oil and natural gas, secure trained personnel and adequately compensate personnel could have a material adverse effect on our production, revenues and results of operations.
Market conditions or operational impediments may hinder our access to oil and natural gas markets or delay our production.
Market conditions or the unavailability of satisfactory oil and natural gas processing or transportation arrangements may hinder our access to oil and natural gas markets or delay our production. The availability of a ready market for our oil and natural gas production depends on a number of factors, including the demand for and supply of oil and natural gas, the proximity of reserves to pipelines and storage facilities, gathering systems and other transportation, processing, fractionation, refining and export facilities, competition for such facilities and the inability of such facilities to gather, transport or process our production due to shutdowns or curtailments arising from mechanical, operational or weather related matters, including hurricanes and other severe weather conditions. Our ability to market our production depends in substantial part on the availability and capacity of gathering, storage and transportation systems, pipelines and processing facilities owned and operated by third parties. Throughout 2018 and 2019, concerns emerged that Permian oil and natural gas supply would exceed pipeline capacity. Our ability to market our production may be impacted if such constraints continue or become worse in the future. Our failure to obtain such services on acceptable terms or the failure of counterparties to perform under certain of our transportation or marketing arrangements could have a material adverse effect on our business, financial condition and results of operations. We may be required to shut in or otherwise curtail

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production from wells due to lack of a market or inadequacy or unavailability of oil or natural gas pipeline or gathering, storage, transportation or processing capacity and fractionation, refining or export facilities. If that were to occur, then we would be unable to realize revenue from those wells until suitable arrangements were made to market our production.
We are subject to complex federal, state, local and other laws and regulations that could adversely affect the cost, timing, manner or feasibility of conducting our operations or that may subject us to fines or penalties for any failure to comply.
Our oil and natural gas exploration, development and production, and related saltwater disposal operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous permits, approvals and certificates from various federal, state, local and governmental authorities. We may incur substantial costs and experience delays in order to maintain compliance with these existing laws and regulations. If we fail to comply with the existing laws and regulations, we may incur additional costs, including fines and penalties, in order to come back into compliance. In addition, our costs of compliance may increase or our operations may be otherwise adversely affected if existing laws and regulations are revised or reinterpreted or if the government agencies responsible for enforcing certain existing laws and regulations applicable to us change their priorities or policies, or if new laws and regulations become applicable to our operations. These and other costs could have a material adverse effect on our production, revenues and results of operations. In addition, certain candidates for the 2020 presidential election have espoused as part of their overall campaign platform support for climate change regulation and bans on hydraulic fracturing that could materially impact our business. Approximately 20 percent of our acreage was located on federal lands at December 31, 2019. We cannot be certain of the impact of any new legislation at the state or federal level, but it could harm our business, operating results and financial condition. In addition, speculation regarding potential changes in the regulatory environment creates uncertainties that could lead to increased volatility in the market price of our common stock in the short term.
The implementation of derivatives legislation adopted by Congress could have an adverse effect on our ability to use derivative instruments to reduce the effect of commodity price, interest rate and other risks associated with our business.
Congress adopted comprehensive financial reform legislation that establishes federal oversight and regulation of the over-the-counter derivatives market and entities, including us, which participate in that market. This legislation, known as the Dodd-Frank Wall Street Reform and Consumer Protection Act (the “Act”), became law on July 21, 2010 and requires the Commodity Futures Trading Commission (the “CFTC”) and the SEC to promulgate rules and regulations implementing the Act. Although the CFTC has finalized certain regulations, others remain to be finalized or implemented, and it is not possible at this time to predict when this will be accomplished.
In October 2011, the CFTC issued regulations to set position limits for certain futures and option contracts in the major energy markets and for swaps that are their economic equivalents; however, this initial position limits rule was vacated by the U.S. District Court for the District of Columbia in September 2012. The CFTC has subsequently issued proposals for new rules that would place position limits on certain core futures contracts and equivalent swap contracts for or linked to certain physical commodities, subject to certain exceptions for bona fide hedging transactions. As these new position limit rules are not yet final, the impact of those provisions on us is uncertain at this time.
The CFTC has designated certain interest rate swaps and credit default swaps subject to mandatory clearing and the associated rules also will require us, in connection with covered derivative activities, to comply with clearing and trade-execution requirements or take steps to qualify for an exemption to such requirements. The CFTC has not yet proposed rules designating any other classes of swaps, including physical commodity swaps, for mandatory clearing. Although we expect to qualify for the end-user exception from the mandatory clearing requirements for swaps entered to hedge our commercial risks, the application of the mandatory clearing and trade execution requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. If our swaps do not qualify for the end-user exception from mandatory clearing, or if the cost of entering into uncleared swaps becomes prohibitive, we may be required to clear such transactions or our ability to hedge may be impacted. The ultimate effect of the rules and any additional regulations on our business is uncertain at this time.
In addition, certain banking regulators and the CFTC have adopted final rules establishing minimum margin requirements for uncleared swaps. While we are exempt from such requirements for the mandatory exchange of margin for uncleared swaps, the application of such requirements to other market participants, such as swap dealers, may change the cost and availability of the swaps that we use for hedging. Further, if we did not qualify for an exemption and were required to post collateral for our swaps, it could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.
The full impact of the Act and related regulatory requirements upon our business will not be known until the regulations are implemented and the market for derivatives contracts has adjusted. When fully implemented, the Act and any new regulations could increase the operational and transactional cost of derivatives contracts, reduce the availability of derivatives to protect against risks we encounter, reduce our ability to monetize and restructure our existing derivatives contracts, impact commodity prices and affect the number and/or creditworthiness of available counterparties. If we reduce our use of derivatives as a result of the Act and regulations implementing the Act, our results of operations may become more volatile and our cash flows may be less predictable, which could adversely affect our ability to plan for and fund capital expenditures. Any of these consequences could have a material adverse effect on us, our financial condition and our results of operations.

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The loss of our chief executive officer or other key personnel could negatively impact our ability to execute our business strategy.
We depend, and will continue to depend in the foreseeable future, on the services of our chief executive officer, Timothy A. Leach, and other officers and key employees who have extensive experience and expertise in evaluating and analyzing producing oil and natural gas properties and drilling prospects, maximizing production from oil and natural gas properties, marketing oil and natural gas production, and developing and executing acquisition, financing and hedging strategies. Our ability to hire and retain our officers and key employees is important to our continued success and growth. The unexpected loss of the services of one or more of these individuals could negatively impact our ability to execute our business strategy.
Because we do not operate and therefore control the development of certain properties in which we own interests, we may not be able to produce economic quantities of oil and natural gas in a timely manner.
At December 31, 2019, approximately 5 percent of our proved reserves were attributable to properties for which we were not the operator. As a result, the success and timing of drilling and development activities on properties operated by others depend upon a number of factors that are beyond our control, including:
the nature and timing of drilling and operational activities controlled by others;
the timing and amount of the operators’ capital expenditures;
the operators’ expertise and financial resources;
the approval of other participants in such properties; and
the selection and application of suitable technology.
If drilling and development activities are not conducted on these properties or are not conducted as we expect, we may be unable to increase our production or offset normal production declines or we will be required to write-off the reserves attributable to such properties, which may adversely affect our production, revenues and results of operations.
We do not control certain of the entities in which we own equity interests.
Certain of the entities in which we own equity interests are managed by their respective governing bodies, which we do not control. As a result, our ability to influence decisions with respect to the operation of such entities’ businesses and distributions from such entities is limited. Such ability varies depending on the amount of control we exercise under the applicable governing agreement, including with respect to cash distributions, capital calls, capital expenditures and the incurrence of additional indebtedness.
A terrorist or cyber attack or armed conflict could harm our business by decreasing our revenues and increasing our costs.
Terrorist activities, anti-terrorist efforts, cyber attacks and other armed conflicts involving the United States may adversely affect the United States and global economies and could prevent us from meeting our financial and other obligations. If any of these events occur or escalate, the resulting political instability and societal disruption could reduce overall demand for oil and natural gas, potentially putting downward pressure on demand for our production and causing a reduction in our revenue. Oil and natural gas related facilities could be direct targets of terrorist attacks, and our operations could be adversely impacted if significant infrastructure or facilities used for the production, transportation, processing or marketing of oil and natural gas production are destroyed or damaged. Additionally, as an oil and natural gas producer, we constantly face various cybersecurity threats, including threats to gain unauthorized access to sensitive information or to render data or systems unusable, and there can be no assurance that our implementation of various procedures and controls to monitor and mitigate security threats will be sufficient to prevent security breaches from occurring. Costs for insurance, recovery, remediation, potential litigation and other security measures may increase as a result of these threats, and some insurance coverage may become more difficult to obtain, if available at all.
Our reliance on information technology, including those hosted by third parties, exposes us to cyber security risks that could affect our business, financial condition or reputation and increase compliance challenges.
We rely extensively on information technology systems, including internet sites, computer software, data hosting facilities and other hardware and platforms, some of which are hosted by third parties, to assist in conducting our business. Our information technology systems, as well as those of third parties we use in our operations, may be vulnerable to a variety of evolving cybersecurity risks, such as those involving unauthorized access or control, denial-of-service attacks, malicious software, data privacy breaches by employees, insiders or others with authorized access, cyber or phishing-attacks, ransomware, malware, social engineering, physical breaches or other actions. These cybersecurity threat actors, whether internal or external to us, are becoming more sophisticated and coordinated in their attempts to access the company’s information technology systems and data, including the information technology systems of cloud providers and other third parties with whom the company conducts business.

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Although we have implemented information technology controls and systems that are designed to protect information and mitigate the risk of data loss and other cybersecurity risks, such measures cannot entirely eliminate cybersecurity threats, and the enhanced controls we have installed may be breached. If our information technology systems cease to function properly or our cybersecurity is breached, we could suffer disruptions to our normal operations which may include drilling, completion, production and corporate functions. A cyber attack involving our information systems and related infrastructure, or that of our business associates, could negatively impact our operations in a variety of ways, including, but not limited to, the following:
Unauthorized access to seismic data, reserves information, strategic information, or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and natural gas resources;
Data corruption, communication interruption, or other operational disruption during drilling activities could result in failure to reach the intended target or a drilling incident;
Data corruption or operational disruptions of production-related infrastructure could result in a loss of production, or accidental discharge;
A cyber attack on a vendor or service provider could result in supply chain disruptions which could delay or halt our major development projects;
A cyber attack on third-party gathering, pipeline, or rail transportation systems could delay or prevent us from transporting and marketing our production, resulting in a loss of revenues;
A cyber attack which halts activities at a power generation facility or refinery using natural gas as feed stock could have a significant impact on the natural gas market, resulting in reduced demand for our production, lower natural gas prices, and reduced revenues;
A cyber attack on a communications network or power grid could cause operational disruption resulting in loss of revenues;
A cyber attack on our automated and surveillance systems could cause a loss in production and potential environmental hazards;
A cyber attack involving commodities exchanges or financial institutions could slow or halt commodities trading, thus preventing us from marketing our production or engaging in hedging activities, resulting in a loss of revenues;
A deliberate corruption of our financial or operating data could result in events of non-compliance which could then lead to regulatory fines or penalties; and
A cyber attack resulting in the loss or disclosure of, or damage to, our or any of our customer’s, supplier’s or landowner’s data or confidential information could harm our business by damaging our reputation, subjecting us to potential financial or legal liability, and requiring us to incur significant costs, including costs to repair or restore our systems and data or to take other remedial steps.
All of the above could negatively impact our operational and financial results. Additionally, certain cyber incidents, such as surveillance, may remain undetected for an extended period. As cyber threats continue to evolve, we may be required to expend significant additional resources to continue to modify or enhance our protective measures or to investigate and remediate any information security vulnerabilities. Additionally, the growth of cyber attacks has resulted in evolving legal and compliance matters which impose significant costs that are likely to increase over time.

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Risks Related to Our Common Stock
Our certificate of incorporation, our bylaws and Delaware law contain provisions that could discourage acquisition bids or merger proposals, which may adversely affect the market price of our common stock.
Our certificate of incorporation authorizes our board of directors to issue preferred stock without stockholder approval. If our board of directors elects to issue preferred stock, it could be more difficult for a third party to acquire us. In addition, some provisions of our certificate of incorporation, our bylaws and Delaware law could make it more difficult for a third party to acquire control of us, even if the change of control would be beneficial to our stockholders, including:
the organization of our board of directors as a classified board, which allows no more than approximately one-third of our directors to be elected each year;
stockholders cannot remove directors from our board of directors except for cause and then only by the holders of not less than 66 2/3 percent of the voting power of all outstanding voting stock;
the prohibition of stockholder action by written consent; and
limitations on the ability of our stockholders to call special meetings and establish advance notice provisions for stockholder proposals and nominations for elections to the board of directors to be acted upon at meetings of stockholders.
The payment of dividends will be at the discretion of our board of directors.
While the Company declared a quarterly dividend of $0.125 per share for each quarter in 2019 and intends to continue to pay a dividend in the future, the payment and amount of future dividend payments, if any, are subject to declaration by our board of directors. Such payments will depend on various factors, including actual results of operations, liquidity and financial condition, net cash provided by operating activities, restrictions imposed by applicable law, our taxable income, our operating expenses and other factors our board of directors deems relevant. Covenants contained in our Credit Agreement and the indentures governing our senior notes could limit the payment of dividends. The Company is under no obligation to make dividend payments on our common stock and may cease such payments at any time in the future.
The availability of shares for sale in the future could reduce the market price of our common stock.
In the future, we may acquire interests in other companies by using a combination of cash and our common stock or just our common stock. We may also issue securities to raise cash for acquisitions. We may also issue securities convertible into, or exchangeable for, or that represent the right to receive, our common stock. Any of these events may dilute your ownership interest in our Company, reduce our earnings per share and have an adverse impact on the price of our common stock.
In addition, sales of a substantial amount of our common stock in the public market, or the perception that these sales may occur, could reduce the market price of our common stock. This could also impair our ability to raise additional capital through the sale of our securities.
We cannot guarantee that our recently announced share repurchase program will be fully consummated or that such program will enhance the long-term value of our common stock.

In September 2019, we announced that our board of directors authorized the initiation of a $1.5 billion share repurchase program. We funded the 2019 repurchases primarily with proceeds from our New Mexico Shelf divestiture, which closed in November 2019. The Company is under no obligation to repurchase any specific dollar amount of common stock, and the repurchase program may be extended, suspended or discontinued at any time by our board of directors. As such, we cannot guarantee that this program will be fully consummated, or that such program will enhance the long-term value of our common stock. The extent to which we repurchase our common stock and the timing and funding of such repurchases are dependent upon a variety of factors, including market conditions, regulatory requirements and other corporate considerations, as determined by our management and board of directors. As of December 31, 2019, the Company had repurchased and retired 3,300,370 shares under the program at an aggregate cost of $250 million.
Item 1B.  Unresolved Staff Comments
There are no unresolved staff comments.

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Item 2.  Properties
Our Oil and Natural Gas Reserves
The estimates of our proved reserves at December 31, 2019, all of which were located in the United States, were based on evaluations prepared by the independent petroleum engineering firms of Cawley, Gillespie & Associates, Inc. (“CGA”) and Netherland, Sewell & Associates, Inc. (“NSAI”) (collectively, our “external engineers”). Reserves were estimated in accordance with guidelines established by the SEC and the Financial Accounting Standards Board (the “FASB”).
Internal controls. Our proved reserves are estimated at the property level by external engineers and compiled for reporting purposes by our corporate reservoir engineering staff. We maintain our internal evaluations of our reserves in a secure reserve engineering database. The corporate reservoir engineering staff interact with our internal staff of petroleum engineers, geoscience professionals and land professionals in each of our operating areas and with accounting and marketing employees to obtain the necessary data for the reserves estimation process. Reserves are reviewed and approved internally by members of our senior management and the health, safety, environment and reserves committee, a committee of our board of directors.
Our internal professional staff works closely with our external engineers to ensure the integrity, accuracy and timeliness of data that is furnished to them for their reserve estimation process. All of the reserve information maintained in our secure reserve engineering database is provided to the external engineers. In addition, other pertinent data is provided such as seismic information, geologic maps, well logs, production tests, material balance calculations, well performance data, operating procedures and relevant economic criteria. We make available all information requested, including our pertinent personnel, to the external engineers as part of their preparation of our reserves.
Qualifications of responsible technical persons
Keith Corbett is our Senior Vice President of Corporate Engineering and Planning. In this role, Mr. Corbett is responsible for corporate reservoir engineering and strategic planning. Mr. Corbett joined the Company in 2005 as a Reservoir Engineer and has served in several Asset Manager roles and as an Operations Supervisor before he was appointed as Vice President of Texas (later, Vice President of Midland Basin) in 2015. Prior to joining Concho, Mr. Corbett held drilling, reservoir and production engineering positions at Pennzoil (later Devon Energy) and Stallion Energy. Mr. Corbett is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.
Rick Morton joined the Company in 2011 and currently serves as the Corporate Engineering Director. Prior to joining the Company, Mr. Morton served as Division Acquisition Coordinator for EOG Resources, Inc. Mr. Morton was also previously employed by Southwest Royalties, Inc. as Vice President and Exploitation Manager and by Merit Energy Company in various engineering positions. Mr. Morton began his career in 1983 with Arco Oil and Gas Company as an Operations/Analytical Engineer before moving to a Production Supervisor position. He is a graduate of Texas A&M University with a Bachelor of Science degree in Petroleum Engineering.
CGA. Approximately 55 percent of the proved reserves estimates shown herein at December 31, 2019 have been independently prepared by CGA, a leader of petroleum property analysis for industry and financial institutions. CGA was founded in 1960 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-693. Within CGA, the technical person primarily responsible for preparing the estimates set forth in the CGA letter dated January 27, 2020, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Zane Meekins. Mr. Meekins has been a practicing consulting petroleum engineer at CGA since 1989. Mr. Meekins is a Registered Professional Engineer in the State of Texas (License No. 71055) and has over 32 years of practical experience in petroleum engineering, with over 30 years of experience in the estimation and evaluation of reserves. He graduated from Texas A&M University in 1987 with a Bachelor of Science degree in Petroleum Engineering. Mr. Meekins meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.
NSAI. Approximately 45 percent of the proved reserve estimates shown herein at December 31, 2019 have been independently prepared by NSAI, a worldwide leader of petroleum property analysis for industry and financial organizations and government agencies. NSAI was founded in 1961 and performs consulting petroleum engineering services under Texas Board of Professional Engineers Registration No. F-2699. Within NSAI, the technical person primarily responsible for preparing the estimates set forth in the NSAI letter dated January 23, 2020, filed as an exhibit to this Annual Report on Form 10-K, was Mr. Craig H. Adams. Mr. Adams, a Licensed Professional Engineer in the State of Texas (License No. 68137), has been practicing consulting petroleum engineering at NSAI since 1997 and has over 12 years of prior industry experience. He graduated from Texas Tech University in 1985 with a Bachelor of Science Degree in Petroleum Engineering. Mr. Adams meets or exceeds the education, training, and experience requirements set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers; he is proficient in judiciously applying industry standard practices to engineering and geoscience evaluations as well as applying SEC and other industry reserve definitions and guidelines.

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Table of Contents

Our oil and natural gas reserves. The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2019. Our reserve estimates and our calculation of future net cash flows are based on SEC pricing of (i) $52.19 per Bbl WTI posted oil price and $2.58 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality differentials by property.
 
Oil
(MMBbl)
 
Natural Gas
(Bcf)
 
Total
(MMBoe)
Operating Areas:
 
 
 
 
 
Delaware Basin
339

 
1,300

 
556

Midland Basin
280

 
998

 
446

Total