10-K 1 cxo201710K.htm FORM 10-K  

 

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

 

FORM 10-K

 

 

 

 

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

For the fiscal year ended December 31, 2017

or

 

 

 

o

 

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

 

(I.R.S. Employer

of incorporation or organization)

 

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:

 

 

 

 

 

 

 

Name of each exchange

Title of each class

 

on which registered

 

 

Common Stock, $0.001 par value

 

New York Stock Exchange

 

Securities Registered Pursuant to Section 12(g) of the Act:  None 

 

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

 

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

 

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

 

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted 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 and post such files).   Yes ☑  No o  

 

Indicate by check mark if disclosure of delinquent filers pursuant to Item 405 of Regulation S-K (§229.405 of this chapter) is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.   ☑ 

 

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   (Do not check if a smaller reporting company)

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 o No ☑ 

 

 

 

 

 

 

 

 

 

 

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:

 

$

17,883,517,337

 

 

 

 

 

 

Number of shares of the registrant’s common stock outstanding as of February 16, 2018:

 

 

149,067,852

 

 

 

Documents Incorporated by Reference:

 

Portions of the registrant’s definitive proxy statement for its 2018 Annual Meeting of Stockholders, which will be filed with the United States Securities and Exchange Commission within 120 days of December 31, 2017, are incorporated by reference into Part III of this Form 10-K for the year ended December 31, 2017.

  

 


 

TABLE OF CONTENTS

 

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS  

1

 

 

PART I  

2

Item 1. Business  

2

General  

2

Business and Properties  

2

Summary of Core Operating Areas  

3

Drilling Activities  

5

Our Production, Prices and Expenses  

6

Productive Wells  

7

Marketing Arrangements  

8

Our Principal Customers  

8

Competition  

8

Working Capital

9

Applicable Laws and Regulations  

10

Our Employees  

14

Available Information  

15

Non-GAAP Financial Measures and Reconciliations  

16

Item 1A. Risk Factors  

18

Risks Related to Our Business  

18

Risks Related to Our Common Stock  

34

Item 1B. Unresolved Staff Comments  

34

Item 2. Properties  

34

Our Oil and Natural Gas Reserves  

34

Developed and Undeveloped Acreage  

38

Title to Our Properties  

40

Item 3. Legal Proceedings  

40

Item 4. Mine Safety Disclosures

40

 

 

PART II  

41

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

41

Market Information  

41

Dividend Policy  

41

Repurchases of Equity Securities  

41

Item 6. Selected Financial Data  

42

Selected Historical Financial Information  

42

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

45

Overview  

45

Financial and Operating Performance  

46

Commodity Prices  

47

Recent Events  

48

Derivative Financial Instruments  

49

Results of Operations  

50

Year Ended December 31, 2017 Compared to Year Ended December 31, 2016

52

Year Ended December 31, 2016 Compared to Year Ended December 31, 2015  

59

Capital Commitments, Capital Resources and Liquidity  

65

Critical Accounting Policies and Practices  

70

Recent Accounting Pronouncements  

74

Item 7A. Quantitative and Qualitative Disclosures About Market Risk  

75

Credit risk  

75

Commodity price risk  

75

Interest rate risk  

76

Item 8. Financial Statements and Supplementary Data  

77

 

i 


 

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure  

77

Item 9A. Controls and Procedures

77

Evaluation of Disclosure Controls and Procedures  

77

Changes in Internal Control over Financial Reporting  

77

Management’s Report on Internal Control over Financial Reporting

77

Report of Independent Registered Public Accounting Firm

78

Item 9B. Other Information  

79

 

 

PART III  

80

Item 10. Directors, Executive Officers and Corporate Governance  

80

Code of Ethics

80

Item 11. Executive Compensation  

80

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

80

Equity Compensation Plans  

80

Item 13. Certain Relationships and Related Transactions, and Director Independence

81

Item 14. Principal Accounting Fees and Services  

81

 

 

PART IV  

82

Item 15. Exhibits, Financial Statement Schedules

82

Item 16. Form 10-K Summary

85

 

 

SIGNATURES  

86

GLOSSARY OF TERMS  

88

INDEX TO CONSOLIDATED FINANCIAL STATEMENTS  

F-1

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

ii 


 

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 and Section 21E of the Securities Exchange Act of 1934 (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, capital expenditures, liquidity and capital resources, the timing and success of specific projects, outcomes and effects of litigation, claims and disputes, derivative activities and potential financing. Forward-looking statements are generally accompanied by words such as “estimate,” “project,” “predict,” “believe,” “expect,” “anticipate,” “potential,” “could,” “may,” “foresee,” “plan,” “goal” or other words that convey the uncertainty of future events or 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, 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, or the sustained depression of, the prices we receive for our oil and natural gas;

·          uncertainties about the estimated quantities of oil and natural gas reserves;

·          the costs and availability of equipment, resources, services and qualified personnel required to perform our drilling, completion and operating activities;

·          disruptions to, capacity constraints in or other limitations on the pipeline systems that deliver our oil, natural gas liquids and natural gas and other processing and transportation considerations;

·          drilling, completion and operating risks;

·          environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

·          risks related to the concentration of our operations in the Permian Basin of southeast New Mexico and west Texas;

·          risks associated with acquisitions, including liabilities associated with acquired properties or businesses and the ability to realize expected benefits;

·          the effects of government regulation, permitting and other legal requirements, including new legislation or regulation related to hydraulic fracturing, climate change, derivatives reform or the export of oil and natural gas;

·          the impact of current and potential changes to federal or state tax rules and regulations, including the Tax Cuts and Jobs Act;

·          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;

·          the impact of potential changes in our credit ratings;

·          uncertainties about our ability to successfully execute our business and financial plans and strategies;

·          evolving cybersecurity risks, such as those involving unauthorized access, 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;

·          uncertainties about our ability to replace reserves and economically develop our current reserves;

·          general economic and business conditions, either internationally or domestically;

·          competition in the oil and natural gas industry; and

·          uncertainty concerning our assumed or possible future results of operations.

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.

1 


 

PART I

 

Item 1. Business

 

General

 

Concho Resources Inc., a Delaware corporation (“Concho,” the “Company,” “we,” “us” and “our”) formed 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 core operations are primarily focused in the Permian Basin of southeast New Mexico and west Texas. 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 enhanced recovery potential. Currently, the majority of the rigs running in the Permian Basin are drilling horizontal wells. Concho’s legacy in the Permian Basin provides us a deep understanding of operating and geological trends. We are actively developing our resource base by utilizing extended length lateral drilling, enhanced completion techniques, multi-well pad locations and large-scale development projects throughout our four core operating areas: the Northern Delaware Basin, the Southern Delaware Basin, the Midland Basin and the New Mexico Shelf. Our strategy remains focused on development and exploration activities on our multi-year project inventory and pursuing acquisitions that meet our strategic and financial objectives.

 

Business and Properties

 

Our core operations are focused in the Permian Basin, which underlies an area of southeast New Mexico and west Texas 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, 2017, substantially all of our 840 MMBoe total estimated proved reserves were located in our core operating areas and consisted of approximately 60 percent oil and 40 percent natural gas. We have assembled a multi-year inventory of horizontal development and exploration projects across our four core operating areas.

2 


 

The following table sets forth information with respect to drilling of wells commenced during the periods indicated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

 

 

 

2017

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross wells

 

 

311

 

 

249

 

 

361

Net wells

 

 

197

 

 

170

 

 

228

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent of gross wells drilled horizontally

 

 

100%

 

 

100%

 

 

86%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Percent of gross wells:

 

 

 

 

 

 

 

 

 

 

Producers

 

 

61%

 

 

56%

 

 

74%

 

Unsuccessful

 

 

1%

 

 

-

 

 

1%

 

Awaiting completion at year-end

 

 

38%

 

 

44%

 

 

25%

 

 

 

 

100%

 

 

100%

 

 

100%

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Summary of Core Operating Areas

 

The following is a summary of information regarding our core operating areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Estimated

 

 

 

 

 

Total

 

Total

 

2017 Average

 

 

 

Proved

 

 

 

 

 

Gross

 

Net

 

Daily

 

 

 

Reserves

 

 

 

% Proved

 

Acreage

 

Acreage

 

Production

Core Operating Areas

 

(MMBoe)

 

% Oil

 

Developed

 

(in thousands)

 

(in thousands)

 

(MBoe per Day)

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Delaware Basin

 

295

 

50%

 

68%

 

373

 

259

 

90

Southern Delaware Basin

 

127

 

72%

 

62%

 

146

 

94

 

27

Midland Basin

 

266

 

66%

 

67%

 

265

 

154

 

45

New Mexico Shelf

 

152

 

56%

 

87%

 

121

 

78

 

31

 

Total

 

840

 

60%

 

70%

 

905

 

585

 

193

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Core operating areas

 

Northern Delaware Basin. At December 31, 2017, we had estimated proved reserves in this area of 295 MMBoe, representing  35 percent of our total proved reserves.

 

The Northern Delaware Basin is characterized by a thick, resource-rich hydrocarbon column that lends itself to multi-zone development.  We leverage leading-edge horizontal drilling and completion technologies, utilizing multi-well pad sites to develop multiple producing formations. Our activity has targeted the Avalon shale and Bone Spring and Wolfcamp formations at depths from 6,500 to 13,500 feet.  We continue to test and develop additional landing intervals within these formations.

 

During the year ended December 31, 2017, we commenced drilling or participated in the drilling of 149 (78 net) wells in this area. Throughout 2017, we completed 126 (66 net) wells that are producing. Additionally in 2017, we abandoned 1 (1 net) well that was spud in 2014 and used to monitor offsetting well stimulations. During 2017, we continued (i) development and step-out activity targeting the Avalon shale, Bone Spring sands and Wolfcamp formation and (ii) to refine our completion techniques. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.

 

Southern Delaware Basin. At December 31, 2017, we had estimated proved reserves in this area of 128 MMBoe, representing  15 percent of our total proved reserves.

 

Across our Southern Delaware Basin acreage position, we primarily target the Bone Spring and Wolfcamp formations, which generally range from 8,000 to 12,500 feet in depth.  We leverage leading-edge horizontal drilling and completion technologies, utilizing multi-well pad sites and extended lateral lengths, to develop these producing formations.

 

During the year ended December 31, 2017, we commenced drilling or participated in the drilling of 61 (38 net) wells in this area. Throughout 2017, we completed 53 (33 net) wells that are producing. Additionally in 2017, we spud 2 (2 net) wells that were subsequently abandoned due to mechanical issues. During 2017, we continued (i) development and step-out activity

3 


 

targeting the Bone Spring sands and Wolfcamp shale and (ii) evaluation of our enhanced stimulation procedures of certain horizontal wells. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.

 

Midland Basin. At December 31, 2017, we had estimated proved reserves in this area of 266 MMBoe, representing 32 percent of our total proved reserves.

 

Our primary objectives in the Midland Basin area are the Spraberry and Wolfcamp formations, which are typically encountered at depths of 7,500 feet to 11,500 feet. On our Midland Basin assets, we are developing these formations with horizontal drilling, utilizing multi-well pad sites and extended lateral development. We are also continuing to optimize well spacing, landing intervals and completion techniques.

 

During the year ended December 31, 2017, we commenced drilling or participated in the drilling of 58 (47 net) wells in this area. Throughout 2017, we completed 78 (49 net) wells that are producing. Additionally in 2017, we spud 1 (1 net) well that was subsequently abandoned due to mechanical issues. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.

 

New Mexico Shelf.  At December 31, 2017, we had estimated proved reserves in this area of 151 MMBoe, representing 18 percent of our total proved reserves.

 

Within this area our primary objectives are the Yeso, San Andres and Grayburg formations, with producing depths ranging from approximately 900 feet to 7,500 feet. During 2017, we continued our horizontal drilling of the Yeso formation.

 

During the year ended December 31, 2017, we commenced drilling or participated in the drilling of 43 (34 net) wells in this area. Throughout 2017, we completed 48 (39 net) wells that are producing. During 2017, all of the wells we commenced or participated in drilling were drilled horizontally.

4 


 

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,

 

 

 

 

 

2017

 

2016

 

2015

 

 

 

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Development wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

96

 

76

 

95

 

76

 

180

 

116

 

Dry

 

1

 

1

 

-

 

-

 

1

 

1

Exploratory wells:

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

209

 

112

 

131

 

83

 

260

 

154

 

Dry

 

3

 

3

 

1

 

1

 

3

 

2

 

 

Total wells:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Productive

 

305

 

188

 

226

 

159

 

440

 

270

 

 

 

Dry (a)

 

4

 

4

 

1

 

1

 

4

 

3

 

 

 

     Total  

 

309

 

192

 

227

 

160

 

444

 

273

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

The dry hole category includes 4 (4 net) wells that were unsuccessful due to mechanical or other issues for the year ended December 31, 2017.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Present activities. The following table sets forth information about wells for which drilling was in-progress or are pending completion at December 31, 2017, which are not included in the above table:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Drilling In-Progress

 

Pending Completion

 

 

 

Gross

 

Net

 

Gross

 

Net

 

 

 

 

 

 

 

 

 

 

Development and exploratory wells

 

35

 

22

 

85

 

49

 

 

 

 

 

 

 

 

 

 

5 


 

Our Production, Prices and Expenses

 

The following table sets forth summary information concerning our production and operating data for the years ended December 31, 2017, 2016 and 2015. The actual historical data in this table excludes results from our acquisition of certain assets of Reliance Energy, Inc. (the “Reliance Acquisition”) for periods prior to October 2016. 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,

 

 

 

 

 

 

2017

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Production and operating data:

 

 

 

 

 

 

 

 

 

 

Net production volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (MBbl)

  

 

43,472

 

 

33,840

 

 

34,457

 

 

Natural gas (MMcf)

  

 

161,089

 

 

127,481

 

 

106,987

 

 

Total (MBoe)

  

 

70,320

 

 

55,087

 

 

52,288

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average daily production volumes:

 

 

 

 

 

 

 

 

 

 

 

Oil (Bbl)

  

 

119,101

 

 

92,459

 

 

94,403

 

 

Natural gas (Mcf)

  

 

441,340

 

 

348,309

 

 

293,115

 

 

Total (Boe)

  

 

192,658

 

 

150,511

 

 

143,256

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Average prices per unit:

  

 

 

 

 

 

 

 

 

 

 

Oil, without derivatives (Bbl)

  

$

48.13

 

$

39.90

 

$

44.69

 

 

Oil, with derivatives (Bbl) (a)

  

$

49.93

 

$

57.90

 

$

62.03

 

 

Natural gas, without derivatives (Mcf)

  

$

3.07

 

$

2.23

 

$

2.46

 

 

Natural gas, with derivatives (Mcf) (a)

  

$

3.06

 

$

2.36

 

$

2.80

 

 

Total, without derivatives (Boe)

  

$

36.78

 

$

29.68

 

$

34.49

 

 

Total, with derivatives (Boe) (a)

  

$

37.88

 

$

41.03

 

$

46.60

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Operating costs and expenses per Boe: (b)

  

 

 

 

 

 

 

 

 

 

 

Oil and natural gas production

  

$

5.80

 

$

5.81

 

$

7.46

 

 

Production and ad valorem taxes

  

$

2.82

 

$

2.38

 

$

2.90

 

 

Depreciation, depletion and amortization

  

$

16.29

 

$

21.19

 

$

23.40

 

 

General and administrative

  

$

3.46

 

$

4.09

 

$

4.42

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

(a)

Includes the effect of net cash receipts from derivatives:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

  

 

 

  

Years Ended December 31,

 

 

(in millions)

 

2017

 

2016

 

2015

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net cash receipts from derivatives:

 

 

 

 

 

Oil derivatives

 

$

79

 

$

609

 

$

597

 

 

 

Natural gas derivatives

 

 

-

 

 

16

 

 

36

 

 

 

 

Total

 

$

79

  

$

625

  

$

633

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

The presentation of average prices with derivatives is a result of including the net cash receipts from commodity derivatives that are presented in our 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.

 

 

 

 

 

(b)

Per Boe amounts calculated using dollars and volumes rounded to thousands.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

6 


 

Productive Wells

 

The following table sets forth the number of productive oil and natural gas wells on our properties at December 31, 2017, 2016 and 2015. This table does not include wells in which we own a royalty interest only.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Gross Productive Wells

 

Net Productive Wells

 

 

 

 

 

 

 

Natural

 

 

 

 

 

Natural

 

 

 

 

 

 

 

Oil

 

Gas

 

Total

 

Oil

 

Gas

 

Total

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2017

 

 

 

 

 

 

 

 

 

 

 

 

 

Core Operating Areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Delaware Basin

 

1,282

 

439

 

1,721

 

726

 

213

 

939

 

 

Southern Delaware Basin

 

319

 

26

 

345

 

195

 

17

 

212

 

 

Midland Basin

 

2,747

 

15

 

2,762

 

1,675

 

6

 

1,681

 

 

New Mexico Shelf

 

3,200

 

121

 

3,321

 

2,548

 

44

 

2,592

 

Other

 

-

 

3

 

3

 

-

 

-

 

-

 

 

 

Total

 

7,548

 

604

 

8,152

 

5,144

 

280

 

5,424

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2016

 

 

 

 

 

 

 

 

 

 

 

 

 

Core Operating Areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Delaware Basin

 

1,164

 

454

 

1,618

 

662

 

212

 

874

 

 

Southern Delaware Basin

 

270

 

27

 

297

 

163

 

17

 

180

 

 

Midland Basin

 

2,577

 

15

 

2,592

 

1,298

 

5

 

1,303

 

 

New Mexico Shelf

 

3,222

 

126

 

3,348

 

2,560

 

33

 

2,593

 

Other

 

-

 

3

 

3

 

-

 

-

 

-

 

 

 

Total

 

7,233

 

625

 

7,858

 

4,683

 

267

 

4,950

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31, 2015

 

 

 

 

 

 

 

 

 

 

 

 

 

Core Operating Areas:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Northern Delaware Basin

 

1,141

 

460

 

1,601

 

651

 

217

 

868

 

 

Southern Delaware Basin

 

222

 

53

 

275

 

138

 

29

 

167

 

 

Midland Basin

 

2,476

 

24

 

2,500

 

1,173

 

8

 

1,181

 

 

New Mexico Shelf

 

3,143

 

114

 

3,257

 

2,531

 

42

 

2,573

 

Other

 

-

 

3

 

3

 

-

 

 0  

 

 0  

 

 

 

Total

 

6,982

 

654

 

7,636

 

4,493

 

296

 

4,789

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

7 


 

Marketing Arrangements

 

General. We market our oil and natural gas in accordance with standard energy industry practices. The marketing effort endeavors 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. This planning also involves the coordination of access to the physical facilities necessary to connect forthcoming wells as efficiently as possible.

 

Oil. We generally do not transport, refine or process the oil we produce. The majority of our oil in southeast New Mexico is connected directly to oil gathering pipelines. Most of our gathered oil from the New Mexico Shelf is utilized in a two-refinery complex in southeast New Mexico. Most of our oil production from the New Mexico portion of our Northern Delaware Basin core area is now connected to the Alpha Crude Connector, LLC (“ACC”) pipeline system. Most of the oil production connected to the ACC pipeline system is purchased by three different purchasers and moved on several different pipeline outlets connected to ACC. We have assigned our shipping rights on ACC to these purchasers and they purchase our production at the receipt points that are connected at our lease tank batteries into ACC. The remaining oil in our Northern Delaware Basin core area is purchased by approximately five different oil purchasers and trucked to regional pipeline stations.

 

Most of our oil in the Southern Delaware Basin is on one of three different oil gathering systems. One of these systems is a crude oil gathering and transportation system operated by a subsidiary of Oryx Southern Delaware Holdings, LLC (“Oryx”), an entity in which we own a 23.75 percent membership interest. The oil is then transported to the Crane/Midland/Colorado City pipeline corridor and then onto Cushing or Gulf Coast markets. A significant portion of our Midland Basin production is on one of six different gathering systems. Most of this production is sweet crude and is transported by third parties to Cushing or Gulf Coast markets. The balance of our oil in these areas that is not directly connected to pipelines is trucked to unloading stations on those same pipelines. We sell the majority of the oil we produce under contracts using market-based pricing. This price is then 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 casinghead 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 purchaser gathers our casinghead natural gas in the field where it is produced and transports it via pipeline to natural gas processing plants where natural gas liquid products are extracted and sold by the processors. The portion of natural gas remaining after liquid extraction is residue gas, which is placed on residue pipeline systems downstream of the subject processing plant. 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 our service.

 

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 2017, revenues from oil and natural gas sales to Plains Marketing and Transportation, Inc. and Holly Frontier Refining and Marketing, LLC accounted for approximately 21 percent and 10 percent, respectively, of our total operating revenues. While the loss of either of these purchasers may result in a temporary interruption in sales of, or a lower price for, our production, we believe that the loss of either of these purchasers would not have a material adverse effect on our operations, as there are alternative purchasers in our producing regions. See Note 12 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 trained 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.

 

8 


 

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 unable to predict the timing or duration of any such 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. At December 31, 2017, we had $322 million of debt outstanding under our credit facility and $1.7 billion of unused commitments under our credit facility. Subsequent to December 31, 2017, our cash position increased by approximately $250 million as a result of completing two divestitures of oil and natural gas properties located in the Southern Delaware Basin core area. 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.

9 


 

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 expensive pollution 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 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. For example, in December 2016, the EPA and certain environmental organizations entered into a consent decree to address EPA’s alleged failure to timely assess its RCRA Subtitle D criteria regulations exempting certain exploration and production related oil and natural gas wastes from regulation as hazardous wastes under RCRA. The consent decree requires EPA to propose a rulemaking no later than March 15, 2019 for revision of certain Subtitle D criteria regulations pertaining to oil and natural gas wastes or to sign a determination that revision of the regulations is not necessary. Any such change could result in an increase in our costs to manage and dispose of wastes, which could have a material adverse effect on our results of operations and financial position. 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.

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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 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, including Texas, 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.

 

In September 2015, new EPA and U.S. Army Corps of Engineers rules to revise the definition of “waters of the United States” (“WOTUS”) for all Clean Water Act programs, thereby defining the scope of the EPA’s and the Corps’ jurisdiction, became effective. To the extent the rule expands the scope of jurisdiction of the Clean Water Act, we could face increased costs and delays with respect to obtaining permits for dredge and fill activities in wetland areas. The rule has been challenged in court on the grounds that it unlawfully expands the reach of Clean Water Act programs, and implementation of the rule has been stayed pending resolution of the court challenge. In response to this decision, the EPA and the Corps resumed nationwide use of the agencies’ prior regulations defining the term “waters of the United States.” Those regulations will be implemented as they were prior to the effective date of the new WOTUS rule. In January 2017, the U.S. Supreme Court accepted review of the WOTUS rule to determine whether jurisdiction to hear challenges to the rule rests with the federal district or appellate courts. In February 2017, the new Presidential administration issued an Executive Order directing the EPA and the Corps to review and, consistent with applicable law, to initiate a rule-making to rescind or revise the WOTUS rule. The EPA and the Corps published a notice of intent to review and rescind or revise the rule in March 2017. In addition, the U.S. Department of Justice filed a motion with the U.S. Supreme Court in March 2017 requesting that the U.S. Supreme Court stay the suit concerning which court should hear challenges to the rule. The U.S. Supreme Court denied the motion in April 2017. In June 2017, the EPA and the U.S. Army Corps proposed a rule that would initiate the first step in a two-step process intended to review and revise the definition of “waters of the United States” consistent with President Trump’s Executive Order. Under the proposal, the first step would be to rescind the May 2015 final rule and put back into effect the narrower language defining “waters of the United States” under the Clean Water Act that existed prior to the rule. The second step would be a notice-and-comment rule-making in which the agencies will conduct a substantive reevaluation of the definition of “waters of the United States.” Finally, in January 2018, the Supreme Court ruled that the WOTUS rule must first be reviewed in federal district courts, remanding the case at issue to the district level and putting the status of the Sixth Circuit’s stay of the new rule into question. Citing uncertainty caused by litigation, the EPA subsequently announced a two year stay of the application of the rule as it undertakes its own review of the rule.

 

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

11 


 

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. For example, in 2016, the Oklahoma Corporation Commission issued various orders and regulations applicable to disposal operations in specific counties in Oklahoma. These rules require that disposal well operators, among other things, conduct additional mechanical integrity testing, make sure that their wells are not injecting wastes into targeted formations, and/or reduce the volumes of wastes disposed in such 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.

 

For example, in October 2015, the EPA lowered the National Ambient Air Quality Standard (“NAAQS”) for ozone from 75 to 70 parts per billion. State implementation of the revised NAAQS could result in stricter permitting requirements, delay or prohibit our ability to obtain such permits, and result in increased expenditures for pollution control equipment, the costs of which could be significant. In addition, in June 2016, the EPA finalized rules under the CAA regarding criteria for aggregating multiple sites into a single source for air-quality permitting purposes applicable to the oil and gas industry. This rule could cause small facilities (such as tank batteries), on an aggregate basis, to be deemed a major source, thereby triggering more stringent air permitting requirements, which in turn could result in operational delays or require us to install costly pollution control equipment. In a separate rulemaking in June 2016, the EPA finalized new air emission control requirements for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. In addition, the rule package extends existing volatile organic compound (“VOC”) standards under the EPA’s Subpart OOOO of the New Source Performance Standards to include previously unregulated equipment within the oil and natural gas source category. However, in June 2017, the EPA proposed a two year stay of the fugitive emissions monitoring requirements, pneumatic pump standards, and closed vent system certification requirements in the 2016 New Source Performance Standards rule for the oil and gas industry while it reconsiders these aspects of the rule. The proposal is still under consideration. The U.S. Bureau of Land Management (“BLM”) finalized similar rules in November 2016 that limit methane emissions from new and existing oil and natural gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM adopted final rules in January 2017. Operators generally had one year from the January 2017 effective date to come into compliance with the rule’s requirements. However, in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrative review of the rule. 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 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. As noted above, both the EPA and 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.

 

On August 3, 2015, the EPA also issued new regulations limiting carbon dioxide emissions from existing power generation facilities. Under this rule, nationwide carbon dioxide emissions would be reduced by approximately 30 percent from 2005 levels by 2030 with a flexible interim goal. Several industry groups and states challenged the rule. On February 9, 2016, the

12 


 

U.S. Supreme Court stayed the implementation of this rule pending judicial review. On March 28, 2017, President Trump signed an Executive Order directing the EPA to review the regulations, and on April 4, 2017, the EPA announced that it was reviewing the 2015 carbon dioxide regulations. On April 28, 2017, the U.S. Court of Appeals for the District of Columbia stayed the litigation pending the current administration’s review. That stay was extended for another 60 days on August 8, 2017. On October 10, 2017, the EPA initiated the formal rulemaking process to repeal the regulations. The EPA’s proposal will be subject to public comment and likely legal challenge, and as such, we cannot predict at this time what impact the rulemaking will have on the demand for oil and natural gas production and our operations.

 

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 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 greenhouse gas 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 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.

 

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

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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.

 

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.

 

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. As noted above, 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, which could reduce demand for our midstream services.

 

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 2018, and we did not incur material capital expenditures relating to environmental issues, claims or regulations during 2017. 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.

 

Our Employees

 

Our corporate headquarters are located at One Concho Center, 600 West Illinois Avenue, Midland, Texas 79701. We also maintain various field offices in Texas and New Mexico. At December 31, 2017, we had 1,203 employees, 457 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

14 


 

stoppages. We consider our relations with our employees to be good. We also utilize the services of contractors to perform various field and other services.

 

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 may read and copy any materials that we file or furnish with the SEC at the SEC’s Public Reference Room at 100 F Street, N.E., Washington, D.C. 20549. The public may obtain information on the operation of the Public Reference Room by calling the SEC at 1-800-SEC-0330. Also, the SEC maintains a website that contains reports, proxy and information statements, and other information regarding issuers, including us, that file or furnish electronically with the SEC. 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 Annual Report on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and, if applicable, amendments to those reports filed or furnished pursuant to Section 13(a) of the Exchange Act as soon as reasonably practicable after we electronically file such material with, or furnish it to, the SEC.

15 


 

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, 2017, 2016 and 2015:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

December 31,

(in millions)

 

2017

 

 

2016

 

 

2015

 

 

 

 

 

 

 

 

 

 

 

Standardized measure of discounted future net cash flows

 

$

7,478

 

$

4,190

 

$

3,739

Present value of future income taxes discounted at 10%

 

 

1,001

 

 

652

 

 

524

 

PV-10

 

$

8,479

 

$

4,842

 

$

4,263

 

 

 

 

 

 

 

 

 

 

 

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Reconciliation of Net Income (Loss) to EBITDAX

 

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 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) non-cash stock-based compensation, (6) (gain) loss on derivatives, (7) net cash receipts from (payments on) derivatives, (8) (gain) loss on disposition of assets, net, (9) interest expense, (10) loss on extinguishment of debt, (11) federal and state income tax expense (benefit) from continuing operations and (12) similar items listed above that are presented in discontinued operations. EBITDAX is not a measure of net income (loss) or cash flows as determined by GAAP.

 

Our EBITDAX measure provides additional information that may be used to better understand our operations. 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 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. EBITDAX, as used by us, may not be comparable to similarly titled measures reported by other companies. We believe that 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, 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.

 

The following table provides a reconciliation of the GAAP measure of net income (loss) to EBITDAX (non-GAAP) for the periods indicated:

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Years Ended December 31,

(in millions)

 

2017

 

2016

 

2015

 

2014

 

2013

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Net income (loss)

 

$

956

 

$

(1,462)

 

$

66

 

$

538

 

$

251

 

Exploration and abandonments

 

 

59

 

 

77

 

 

59

 

 

285

 

 

109

 

Depreciation, depletion and amortization

 

 

1,146

 

 

1,167

 

 

1,223

 

 

980

 

 

773

 

Accretion of discount on asset retirement obligations

 

 

8

 

 

7

 

 

8

 

 

7

 

 

6

 

Impairments of long-lived assets

 

 

-

 

 

1,525

 

 

61

 

 

447

 

 

65

 

Non-cash stock-based compensation

 

 

60

 

 

59

 

 

63

 

 

47

 

 

35

 

(Gain) loss on derivatives

 

 

126

 

 

369

 

 

(700)

 

 

(891)

 

 

124

 

Net cash receipts from (payments on) derivatives

 

 

79

 

 

625

 

 

633

 

 

72

 

 

(32)

 

(Gain) loss on disposition of assets, net

 

 

(678)

 

 

(118)

 

 

54

 

 

9

 

 

1

 

Interest expense

 

 

146

 

 

204

 

 

215

 

 

217

 

 

219

 

Loss on extinguishment of debt

 

 

66

 

 

56

 

 

-

 

 

4

 

 

29

 

Income tax expense (benefit) from continuing operations

 

 

(75)

 

 

(876)

 

 

31

 

 

318

 

 

118

 

Discontinued operations

 

 

-

 

 

-

 

 

-

 

 

-

 

 

(12)

EBITDAX

 

$

1,893

 

$

1,633

 

$

1,713

 

$

2,033

 

$

1,686

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

17 


 

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, natural gas and natural gas liquid prices are volatile. A decline in oil, natural gas and natural gas liquid 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, natural gas and natural gas liquids. Oil, natural gas and natural gas liquid 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, natural gas and natural gas liquids are subject to a variety of factors beyond our control, including:

 

·         the overall global demand for oil, natural gas and natural gas liquids;

 

·         the domestic and foreign supply of oil, natural gas and natural gas liquids;

 

·         the overall North American oil, natural gas and natural gas liquids supply and demand fundamentals, including:

 

       the U.S. economy,

 

       weather conditions, and

 

       liquefied natural gas deliveries to and exports from the United States;

 

·         economic conditions worldwide;

 

·         the level of global inventories;

 

·         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;

 

·         technological advances affecting energy consumption and energy supply;

 

·         the effect of energy conservation efforts;

 

·         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;

 

·         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;

 

·         risks related to the concentration of our operations in the Permian Basin of southeast New Mexico and west Texas and the level of commodity inventory in the Permian Basin;

 

·         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;

 

·         the quality of the oil we produce; and

 

·         the price and availability of alternative fuels.

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Furthermore, oil and natural gas prices continued to be volatile in 2017. For example, the NYMEX oil prices in 2017 ranged from a high of $60.42 to a low of $42.53 per Bbl and the NYMEX natural gas prices in 2017 ranged from a high of $3.72 to a low of $2.56 per MMBtu. Further, the NYMEX oil prices and NYMEX natural gas prices reached highs of $66.14 per Bbl and $3.63 per MMBtu, respectively, during the period from January 1, 2018 to February 16, 2018.

 

Declines in oil, natural gas and natural gas liquid 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, such as those experienced in 2015 to 2017, 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 30 percent of our total estimated proved reserves at December 31, 2017 were undeveloped, and those reserves may not ultimately be developed.

 

At December 31, 2017, approximately 30 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, 2017 includes estimates of total future development costs over the next five years associated with our proved undeveloped reserves of approximately $2.3 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 timeframe. For example, as of December 31, 2017, we wrote-off approximately 61 MMBoe of proved undeveloped reserves because they are no longer expected to be developed 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 or 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:

 

·         shortages of or delays in obtaining equipment and qualified personnel or in obtaining sand or water for hydraulic fracturing activities;

 

·         delays imposed by or resulting from compliance with regulatory and contractual requirements;

 

·         reductions in oil, natural gas and natural gas liquid prices;

 

·         pressure or irregularities in geological formations;

 

·         equipment failures or accidents;

 

·         adverse weather conditions;

 

·         political events, public protests, civil disturbances, terrorist acts or cyber attacks;

 

·         environmental hazards, such as natural gas leaks, oil 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;

 

·         failure to obtain regulatory and third-party approvals;

 

·         actions by third-party operators of our properties;

19 


 

 

·         loss of title or other title related issues;

 

·         delays and costs of drilling wells on lands subject to complex development terms and circumstances;

 

·         oil, natural gas liquids or natural gas gathering, transportation and processing availability restrictions or limitations;

 

·         limitations in the market for oil, natural gas and natural gas liquids; and

 

·         limited availability of financing at acceptable terms.

 

        In addition, the results of our exploratory drilling 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.

 

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. 

 

Oil prices declined substantially during the second half of 2014 and continued to decline through 2016, but began to recover in 2017. In the event that oil prices declined 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.

 

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 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. Restrictions on our ability to obtain 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. Historically, we have been able to purchase water from local land owners and other sources for use in our operations. Over the past few years, extreme drought conditions persisted in west Texas and southeast New Mexico. Although conditions have improved, 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. 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.

20 


 

 

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.

 

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 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 crude 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. For example, in June 2016, the EPA finalized new air emission controls for emissions of methane from certain equipment and processes in the oil and natural gas source category, including production, processing, transmission and storage activities. The final rule package includes first-time standards to address emissions of methane from equipment and processes across the source category, including hydraulically fractured oil and natural gas well completions, and also imposes leak detection and repair requirements on operators. The BLM finalized similar rules in November 2016 that limit methane emissions from new and existing oil and gas operations on federal lands through limitations on the venting and flaring of gas, as well as enhanced leak detection and repair requirements. The BLM adopted the final rules in January 2017. Operators generally had one year from the January 2017 effective date to come into compliance with the rule’s requirements. However,

21 


 

in December 2017, the BLM temporarily suspended or delayed certain of these requirements set forth in its Venting and Flaring Rule until January 2019, pending administrative review of the rule. These methane emission rules have the potential to increase our compliance costs.

 

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 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.

 

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 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. 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 the causation of or contribution to the asserted damage, or to other mitigating factors.

 

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 and ad valorem taxes, development 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. 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

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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, natural gas liquids 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, 2017, we had approximately $322 million of debt outstanding under our credit facility (and total debt at December 31, 2017 of $2.7 billion), and we had approximately $1.7 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 $2.9 billion in acquisition, exploration and development costs during the year ended December 31, 2017. In February 2018, we announced our 2018 capital budget, excluding acquisitions, of approximately $2.0 billion with expected capital spending to range between $1.9 billion and $2.1 billion. Our 2018 capital budget, based on our current expectations of commodity prices and costs, is expected to be funded with our cash flows. We plan to spend approximately $2.3 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 level 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;

 

·         the impact of potential changes in our credit ratings; and

 

·         our proved reserves.

 

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 the 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.

 

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The failure to obtain additional financing could result in a curtailment of our operations relating to the development of our undeveloped acreage, 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, 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. 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.

 

Recently enacted legislation will affect our tax position; however, 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 December 2017, Congress enacted the budget reconciliation act commonly referred to as the Tax Cuts and Jobs Act (“TCJA”). The law made significant changes to U.S. federal income tax laws, including reducing the corporate income tax rate from 35 percent to 21 percent, repealing the corporate alternative minimum tax (“AMT”), partially limiting the deductibility of interest expense and net operating losses (“NOLs”), eliminating the deduction for certain U.S. production activities and allowing the immediate deduction of certain new investments in lieu of depreciation expense over time. Many aspects of the TCJA are unclear and may not be clarified for some time. We will continue to monitor any new administrative guidance or tax law interpretation.

 

In recent years, U.S. lawmakers have proposed certain significant changes to U.S. tax laws applicable to oil and 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 TCJA, it is unclear whether any such changes will be enacted or if enacted, when such changes could be effective. If such proposed changes were to be enacted, as well as any similar changes in state law, it could 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, 2017, we had approximately $122 million of federal NOL carryforwards available to offset against future taxable income. These NOL carryforwards, generated prior to the effective date of new limitations on utilization of NOLs imposed by the TCJA, are allowable as a deduction against 100 percent of taxable income in future years but will expire in the tax year 2036. Utilization of any NOL depends on many factors, including our ability to generate future taxable income, which cannot be assured. In addition, Section 382 of the Internal Revenue Code of 1986, as amended (“Section 382”), generally imposes an annual limitation on the amount of NOLs that may be used to offset taxable income 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 our NOLs 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 recent equity offerings or our issuance of shares in connection with various acquisitions. As such, Section 382 was not expected to limit our ability to utilize our NOL carryforward or any other tax attribute at December 31, 2017. Future ownership changes or future regulatory changes could limit our ability to utilize our NOLs. To the extent we are not able to offset our future income with our NOLs, this could adversely affect our operating results and cash flows once we attain profitability.

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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 $2.7 billion of outstanding debt at December 31, 2017. At December 31, 2017, commitments from our bank group were $2.0 billion, of which $1.7 billion was unused commitments.

 

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 to the extent we do not have applicable interest rate fluctuation hedges. The amount of our debt may also cause us to be more vulnerable to economic downturns and adverse developments in our business.

 

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, increasing our vulnerability to adverse changes in general economic and industry conditions and limiting our ability to sell assets, engage in strategic transactions or obtain additional financing for working capital, capital expenditures, general corporate and other purposes. If we incur additional debt, the related risks that we now face could intensify. A higher level of indebtedness also increases the risk that we may default on our debt obligations. 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 beyond 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 seek a waiver, we may not be able to obtain a waiver from the required lenders. If this occurs, 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 August 2017, our long-term debt was assigned a first-time investment grade rating by Fitch, and our rating by S&P was raised to an investment grade rating. 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

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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, which had the effect of releasing all collateral formerly securing the 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 the 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. 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, 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 southeast New Mexico and west Texas, 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 southeast New Mexico and west Texas. At December 31, 2017, substantially all of our total estimated proved reserves were attributable to properties located in this area. As a result of this 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, market limitations, severe weather events, water shortages or other drought related conditions or interruption of the processing or transportation of oil, natural gas or natural gas liquids.

 

In addition to the geographic concentration of our producing properties described above, at December 31, 2017, approximately: (i) 35 percent of our proved reserves were attributable to the Northern Delaware Basin core area that primarily targets the Avalon shale and Bone Spring and Wolfcamp formations; (ii) 15 percent of our proved reserves were attributable to the Southern Delaware Basin core area that primarily targets the Bone Spring and Wolfcamp formations; (iii) 32 percent of our proved reserves were attributable to the Midland Basin core area that primarily targets the Wolfcamp and Spraberry formations; and (iv) 18 percent of our proved reserves were attributable to the New Mexico Shelf core area that primarily targets the Yeso formation, which includes both the Paddock and Blinebry intervals underlying our oil and natural gas properties located in southeast New Mexico. 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, 2017, we carried unproved property costs of $2.7 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, 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.

 

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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 $1.5 billion and $61 million in 2016 and 2015, respectively. We did not incur an impairment charge in 2017.

 

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, 2017, we had a net derivative liability of approximately $379 million. An average increase in the commodity price of $5.00 per barrel of oil and $0.50 per MMBtu for natural gas from the commodity price at December 31, 2017 would have resulted in an increase in our net liability of approximately $327  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 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.

 

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 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.

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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 are based on SEC pricing of (i) $47.79  per Bbl WTI posted oil price and (ii) $2.98  per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property. The SEC pricing for reserves as of December 31, 2017 is lower than the NYMEX oil price of $61.68 per Bbl at February 16, 2018 but higher than the NYMEX natural gas price of $2.56 per MMBtu at February 16, 2018. If average oil prices were $5.00 per barrel lower than the average price we used, our PV-10 at December 31, 2017 would have decreased from $8.5 billion to $7.4 billion. If average natural gas prices were $0.50 per MMBtu lower than the average price we used, our PV-10 at December 31, 2017 would have decreased from $8.5 billion to $8.1 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 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 the 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.

 

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

 

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·         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 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. Further, our drilling operations may be curtailed, delayed or canceled as a result of numerous factors, including:

 

·         unexpected drilling conditions;

 

·         title problems;

 

·         risks associated with drilling horizontal wells and extended lateral lengths, such as deviating from the desired drilling zone or not running casing or tools consistently through the wellbore, particularly as lateral lengths get longer;

 

·         pressure or irregularities in formations;

 

·         equipment failures or accidents;

 

·         fracture stimulation accidents or failures;

 

·         adverse weather conditions;

 

·         compliance with environmental and other governmental or contractual requirements; and

 

·         increases in the cost of, or shortages or delays in the availability of, electricity, water, supplies, materials, drilling or workover rigs, equipment and services.

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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:

 

·         environmental hazards, such as uncontrollable flows of oil, natural gas, brine, well fluids, toxic gas or other pollution into the environment, including groundwater contamination;

 

·         abnormally pressured or structured formations;

 

·         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 and secure trained personnel and adequately compensate personnel could have a material adverse effect on our production, revenues and results of operations.

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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, natural gas and natural gas liquid 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, natural gas and natural gas liquids, the proximity of reserves to pipelines and terminal 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 and transportation systems, pipelines and processing facilities owned and operated by third parties. Our failure to obtain such services on acceptable terms 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 production from wells due to lack of a market or inadequacy or unavailability of oil, natural gas liquid or natural gas pipeline or gathering, transportation or processing capacity. 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.

 

The adoption of derivatives legislation 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 commercial 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. Although we expect to qualify for the end-user exception from such margin requirements for swaps entered into to hedge our commercial risks, 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. If any of our swaps do not qualify for the commercial end-user exception, the posting of collateral could reduce our liquidity and cash available for capital expenditures and our ability to manage commodity price volatility and the volatility in cash flows.

 

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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.

 

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 of the 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, 2017, approximately 7 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.

 

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 conflict 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 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.

 

32 


 

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, 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.

 

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 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 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 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 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 or supplier’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.

33 


 

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.

 

Because we have not historically and do not have immediate plans to pay dividends on our common stock, investors are currently limited to stock appreciation for a return on their investment in us. 

 

We do not have plans to pay cash dividends on our common stock in the near future. We currently intend to retain future earnings to fund the development and growth of our business. Any payment of future dividends will be at the discretion of our board of directors and will depend on, among other things, our earnings, financial condition, capital requirements, level of indebtedness, statutory and contractual restrictions applying to the payment of dividends and other considerations that our board of directors deems relevant. Covenants contained in our credit facility and the indentures governing our senior notes could limit the payment of dividends; however, at December 31, 2017, under our covenants we could pay dividends in excess of $1 billion. Investors must rely on sales of their common stock after price appreciation, which may never occur, as the only way to realize an immediate return on their investment.

 

The availability of shares for sale in the future could reduce the market price of our common stock.

 

In the future, we may issue securities to raise cash for acquisitions. We may also 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 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.

  

Item 1B.  Unresolved Staff Comments

 

There are no unresolved staff comments.

  

Item 2.  Properties

 

Our Oil and Natural Gas Reserves

 

The estimates of our proved reserves at December 31, 2017, 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 reserves committee, a committee of our Board of Directors.

 

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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

 

J. Steve Guthrie has been our Senior Vice President of Business Operations and Engineering since November 2013. Mr. Guthrie previously served as the Vice President of Texas, the Texas Asset Manager and Corporate Engineering Manager. Prior to joining the Company, Mr. Guthrie was employed by Moriah Resources as Business Development Manager, by Henry Petroleum in various engineering and operations capacities and by Exxon in several engineering and operations positions. Mr. Guthrie is a graduate of Texas Tech University with a Bachelor of Science degree in Petroleum Engineering.

 

Rick Morton joined the Company in 2011 as Corporate Engineering Manager. 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 53 percent of the proved reserves estimates shown herein at December 31, 2017 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 19, 2018, 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 30 years of practical experience in petroleum engineering, with over 28 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 47 percent of the proved reserve estimates shown herein at December 31, 2017 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 24, 2018, 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 11 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.

35 


 

Our oil and natural gas reserves. The following table sets forth our estimated proved oil and natural gas reserves at December 31, 2017. Our reserve estimates and our computation of future net cash flows are based on SEC pricing of (i) $47.79 per Bbl WTI posted oil price and $2.98 per MMBtu Henry Hub spot natural gas price, adjusted for location and quality by property.

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

 

Oil

 

Natural Gas

 

Total

 

 

(MMBbl)

 

(Bcf)

 

(MMBoe)

Core Operating Areas:

 

 

 

 

 

 

 

Northern Delaware Basin

 

149

 

878

 

295

 

Southern Delaware Basin

 

92

 

214

 

128

 

Midland Basin

 

175