NOBLE ENERGY INC (Form: 10-K, Received: 02/19/2019 13:00:20)
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ý ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2018
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: 001-07964

IMAGE0A93.JPG
NOBLE ENERGY, INC.
(Exact name of registrant as specified in its charter)
Delaware
 
73-0785597
(State of incorporation)
 
(I.R.S. employer identification number)
1001 Noble Energy Way
 
 
Houston, Texas
 
77070
(Address of principal executive offices)
 
(Zip Code)
(281) 872-3100
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class
 
Name of each exchange on which registered
Common Stock, $0.01 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. ý Yes o 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. o Yes ý 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. ý Yes o No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). ý Yes o No 
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 the 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. ý 
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 definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer x
Accelerated filer o
Non-accelerated filer o
Smaller reporting company o
Emerging growth company o
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. o
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act).o Yes ý No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2018: $17.0 billion.
Number of shares of Common Stock outstanding as of December 31, 2018: 477,643,425.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2019 Annual Meeting of Shareholders to be held on April 23, 2019, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2018, are incorporated by reference into Part III.




TABLE OF CONTENTS

PART I
Items 1. and 2.
2
Item 1A.
25
Item 1B.
40
Item 3.
40
Item 4.
40
PART II
Item 5.
40
Item 6.
43
Item 7.
44
Item 7A.
68
Item 8.
70
Item 9.
135
Item 9A.
135
Item 9B.
135
PART III
Item 10.
135
Item 11.
135
Item 12.
135
Item 13.
135
Item 14.
135
PART IV
Item 15.
136
Item 16.
142





Disclosure Regarding Forward-Looking Statements 
This Annual Report on Form 10-K and the documents incorporated by reference in this report contain forward-looking statements within the meaning of the federal securities laws. Forward-looking statements give our current expectations or forecasts of future events.
These forward-looking statements include, among others, the following: 
our growth strategies;
our future results of operations;
our liquidity and ability to finance our exploration and development activities;
our ability to successfully and economically explore for and develop crude oil, natural gas liquids (NGLs) and natural gas resources;
anticipated trends in our business;
market conditions in the oil and gas industry;
the impact of governmental regulation, including United States (US) federal, state, local, and foreign host government tax regulations, fiscal policies and terms, as well as that involving the protection of the environment or marketing of production and other regulations;
our ability to make and integrate acquisitions or execute divestitures; and
access to resources.
Forward-looking statements are typically identified by use of terms such as “may,” “will,” “expect,” “believe,” “anticipate,” “estimate,” “intend,” and similar words, although some forward-looking statements may be expressed differently. These forward-looking statements are made based upon management’s current plans, expectations, estimates, assumptions and beliefs concerning future events impacting us and therefore involve a number of risks and uncertainties. We caution that forward-looking statements are not guarantees and that actual results could differ materially from those expressed or implied in the forward-looking statements. You should consider carefully the statements under Item 1A. Risk Factors and other sections of this report, which describe factors that could cause our actual results to differ from those set forth in the forward-looking statements.
PART I
Items 1. and 2. Business and Properties
In this report, unless otherwise indicated or where the context otherwise requires, information includes that of Noble Energy, Inc. and its subsidiaries (Noble Energy, the Company, we or us). All references to production, sales volumes and reserves quantities are net to our interest unless otherwise indicated. For a summary of commonly used industry terms and abbreviations used in this report, see the Glossary, located at the end of this report.
Noble Energy (NYSE: NBL) is an independent oil and natural gas exploration and production company committed to meeting the world’s growing energy needs and delivering competitive returns to its shareholders. Founded in 1932 and incorporated in Delaware in 1969, Noble Energy is guided by its values, its commitment to safety, and respect for stakeholders, communities and the environment. For more information on how the Company fulfills its purpose: Energizing the World, Bettering People's Lives®, visit https://www.nblenergy.com. Information on our website is not incorporated by reference into, and does not constitute a part of, this report.
Portfolio Our portfolio of assets is diversified through US and international projects and production mix among crude oil, NGLs and natural gas. In particular, our business is focused on both US onshore unconventional basins and certain global offshore conventional basins in the Eastern Mediterranean and off the west coast of Africa. In US onshore unconventional basins, we have demonstrated our ability to apply geological, drilling, completion, and midstream design and operational expertise. In US onshore, we utilize an Integrated Development Plan (IDP) which applies a major project development approach to an unconventional basin. In the global offshore, we have had notable exploration and major project successes, which have led to major development projects and provided long-lived cash flows to our business.
Capital Program Looking ahead, approximately 70% of our 2019 capital program (excluding capital funded by Noble Midstream Partners and acquisition capital related to the EMG Pipeline) is allocated to US onshore development, primarily focused on liquids-rich opportunities in the Delaware Basin, Denver-Julesburg (DJ) Basin, and Eagle Ford Shale. Eastern Mediterranean capital expenditures, including remaining costs associated with the Leviathan project, represent approximately 20% of the total. The remaining portion of the capital program is designated for the drilling of a crude oil development well in West Africa, and other exploration and corporate activities. See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2019 Capital Investment Program.

2


Reportable Segments We manage our operations by geographic region and the nature of the products and services we offer. We have the following reportable segments: United States, Eastern Mediterranean, West Africa, Other International and Midstream. The geographical reportable segments are in the business of crude oil and natural gas acquisition and exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other financially attractive midstream projects, with current focus areas being the DJ and Delaware Basins. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information.
Divestiture and Acquisition Activities We maintain an active portfolio management program which includes divestitures of assets through asset or equity sales, exchanges or other transactions. Our portfolio transformation executed over the past few years has included divestitures of Gulf of Mexico assets, a 7.5% working interest in Tamar, our 50% interest in CONE Gathering LLC, our investment in CNX Midstream Partners common units, and other non-core US onshore assets. As a result, our divestitures generated cash proceeds of $2.0 billion and $2.1 billion in 2018 and 2017, respectively, which were used to improve our capital structure, fund a portion of our capital program, strengthen our liquidity and return value to shareholders through the share repurchase program. We expect active portfolio management to continue as an element in our strategic program.
Periodically, we may also engage in acquisitions of additional crude oil or natural gas properties and related assets through either direct acquisitions of the assets or acquisitions of entities that own the assets. For example, in January 2018, Noble Midstream Partners LP (Noble Midstream Partners) acquired an interest in Black Diamond (defined below) which completed the acquisition of Saddle Butte Rockies Midstream, LLC and affiliates (collectively, Saddle Butte), and in 2017 we completed the acquisition (Clayton Williams Energy Acquisition) of Clayton Williams Energy, Inc. (Clayton Williams Energy). See Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources and Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Oil and Gas Properties and Activities We search for crude oil and natural gas properties onshore and offshore, and seek to acquire exploration rights and conduct exploration activities in areas of interest. Our activities include geophysical and geological evaluation; analysis of commercial, regulatory and political risks; and exploratory and development drilling leading to production, where appropriate.
Our current portfolio consists primarily of interests in developed and undeveloped crude oil and natural gas leases and concessions. These properties contribute all of our crude oil, NGL and natural gas production, provide additional investment opportunities in proved areas, and offer further exploration opportunities. Our new venture areas provide frontier exploration opportunities, which may result in the establishment of new operational areas in the future. We also own or invest in midstream assets primarily used in the gathering, processing and transportation of our US onshore production. See Midstream – Properties and Activities.

3


The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
WORLDMAP2018.JPG
Development Activities Our development projects have resulted from both exploration success as well as periodic leasing activities which provide entrance to low cost assets. These projects provide opportunities for growth at attractive financial returns. Each project progresses, as appropriate, through the various development phases including appraisal, engineering and design, development drilling, construction and production. While development projects require significant capital investments, typically over a multi-year period, they are expected to offer sustained cash flows during production.
In US onshore, our low production-risk development programs are centered around IDPs and generate efficiencies for upstream and midstream development. IDPs are generally areas of highly contiguous acreage, typically held by production, that accommodate drilling long lateral wells, and other operational synergies. The approach also benefits from the ability to accommodate a flexible capital investment program that can be varied in response to changes in the commodity price environment. We continue to enhance project performance in these areas through design, technology and operational efficiencies.
Offshore, we engage in long-cycle development projects, such as progressing development at the Leviathan natural gas field, offshore Israel, the largest natural gas discovery in our history, and advancing Aseng crude oil development and Alen natural gas monetization in West Africa. Our development activities are discussed in more detail in the sections below.
Exploration Activities  We primarily focus on organic growth from exploration and development drilling activities, concentrating on existing basins or plays where we believe we have strategic competitive advantages or in new basins with attractive geological potential and the opportunity for competitive project financial returns. These advantages are derived from proprietary seismic data and operational expertise, which we believe will generate superior returns over the oil and gas business cycle. We have had substantial historic exploration success in the Levant Basin offshore Eastern Mediterranean and the Douala Basin offshore West Africa, resulting in the successful completion of numerous major development projects. In 2018, we conducted limited exploration activities as we focused our capital expenditures on the development of the Leviathan field and US onshore assets.
Goodwill Impairment  During fourth quarter 2018, primarily resulting from the drop in West Texas Intermediate index (WTI) strip pricing at the end of 2018, we determined that goodwill of $1.3 billion, which had arisen from the Clayton Williams Energy Acquisition, had been fully impaired. We recorded a charge of $1.3 billion. See Item 8. Financial Statements and Supplementary Data – Note 6. Goodwill Impairment.





4


Proved Reserves Disclosures
Proved Oil and Gas Reserves   Proved reserves at December 31, 2018 were as follows:
 
 
Crude Oil and
Condensate
 
NGLs
 
Natural Gas
 
Total
Reserves Category
 
(MMBbls)
 
(MMBbls)
 
(Bcf)
 
(MMBoe)(1)
 
(Percent)
Proved Developed
 
 
 
 
 
 
 
 
 
 
United States
 
165

 
121

 
929

 
442

 
59
%
Israel
 
2

 

 
1,295

 
218

 
29
%
Equatorial Guinea
 
26

 
9

 
355

 
94

 
12
%
Total Proved Developed Reserves
 
193

 
130

 
2,579

 
754

 
100
%
Proved Undeveloped
 
 

 
 
 
 

 
 

 
 
United States
 
255

 
136

 
1,015

 
560

 
48
%
Israel
 
6

 

 
3,635

 
612

 
52
%
Equatorial Guinea
 
3

 

 
2

 
3

 
%
Total Proved Undeveloped Reserves
 
264

 
136

 
4,652

 
1,175

 
100
%
Total Proved Reserves
 
457

 
266

 
7,231

 
1,929

 
 
(1)  Million barrels oil equivalent. Natural gas is converted on the basis of six Mcf of gas per one barrel of crude oil equivalent. This ratio reflects an energy content equivalency and not a price or revenue equivalency. Given commodity price disparities, the price for a barrel of crude oil equivalent for US natural gas and NGLs is significantly less than the price for a barrel of crude oil. In Israel, we sell natural gas under contracts where the majority of the price is fixed, resulting in less commodity price disparity.
Our proved reserves totaled 1,929 MMBoe as of December 31, 2018 as compared with 1,965 MMBoe as of December 31, 2017. Our proved reserves are 52% US and 48% international, and the commodity mix is 37% global liquids (crude oil and NGLs), 46% international natural gas and 17% US natural gas.
We have historically added reserves through our exploration program, development activities, and acquisition of producing properties. Changes in proved reserves were as follows:
 
 
Year Ended December 31,
(MMBoe)
 
2018
 
2017
 
2016
Proved Reserves Beginning of Year
 
1,965

 
1,437

 
1,421

Revisions of Previous Estimates
 
(2
)
 
135

 
64

Extensions, Discoveries and Other Additions
 
223

 
736

 
179

Purchase of Minerals in Place
 

 
57

 
4

Sale of Minerals in Place
 
(128
)
 
(261
)
 
(77
)
Production
 
(129
)
 
(139
)
 
(154
)
Proved Reserves End of Year
 
1,929

 
1,965

 
1,437

For a discussion of changes in proved reserves, see Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
Proved Undeveloped Reserves (PUDs)   As of December 31, 2018, our PUDs totaled 1,175 MMBoe, or 61% of proved reserves. Changes in PUDs were as follows for the year ended December 31, 2018.
(MMBoe)
 
United States
 
Israel
 
Equatorial Guinea
 
Total
Proved Undeveloped Reserves, Beginning of Year
 
482

 
615

 

 
1,097

Revisions of Previous Estimates
 
(23
)
 

 

 
(23
)
Extensions, Discoveries and Other Additions
 
181

 
12

 
3

 
196

Sale of Minerals in Place
 

 
(15
)
 

 
(15
)
Conversion to Proved Developed
 
(80
)
 

 

 
(80
)
Proved Undeveloped Reserves, End of Year
 
560

 
612

 
3

 
1,175


5


Revisions of Previous Estimates PUD revisions included:
Price Revisions US onshore positive price revisions (price impact to opening balance) of 3 MMBoe were due to changes in 12-month average commodity prices.
Non-Price Revisions Positive price revisions were offset by negative non-price revisions of 26 MMBoe, including the following:
the DJ Basin included a positive 8 MMBoe non-price revision, which included a positive revision of approximately 24 MMBoe associated with the adoption of Accounting Standards Codification (ASC) 606, Revenues from Contracts with Customers (ASC 606), partially offset by a negative revision of 16 MMBoe due to removal of PUDs locations due to changes in the previously adopted development plan;
the Delaware Basin included a negative 25 MMBoe non-price revision primarily due to changes in expected recoveries and higher operating and capital costs; and
the Eagle Ford Shale included a negative 9 MMBoe non-price revision primarily due to removal of PUDs locations due to changes in the previously adopted development plan.
Extensions, Discoveries and Other Additions Extensions of proved reserves were primarily due to drilling plans for new wells, of which 94 MMBoe, 69 MMBoe, 18 MMBoe, 12 MMBoe and 3 MMBoe were in the DJ Basin, Delaware Basin, Eagle Ford Shale, Tamar field and Equatorial Guinea, respectively.
US PUDs Locations During the year, we converted 80 MMBoe of our US PUDs, or 17% of our US PUDs beginning balance, to developed status. The majority of these conversions were in the DJ Basin and Delaware Basin. PUDs conversions were less than 20% in 2018 as we allocated a portion of capital to convert unproved reserves for acreage delineation and lease retention, primarily in the Delaware Basin. In 2018, capital spent to convert approximately 25 MMBoe of unproved reserves to proved developed was approximately $355 million. Based on our current inventory of identified horizontal well locations and our anticipated rate of drilling and completion activity, we expect our US PUDs recorded as of December 31, 2018 to be converted to proved developed reserves within five years of initial recognition.
Our PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required for completion, such as drilled but uncompleted (DUC) wells. As of December 31, 2018, 99 MMBoe of PUDs were associated with US onshore DUC well locations, with 42%, 33% and 25% of locations in the DJ Basin, Delaware Basin and Eagle Ford Shale, respectively.
International PUDs Locations PUDs in the Tamar field decreased 15 MMBoe due to the first quarter 2018 sale of a 7.5% working interest. The PUDs in our Tamar Southwest field represent less than 5% of our international PUDs. These PUDs are expected to remain undeveloped for five years or longer since initial disclosure in 2013. We have been working with the government of Israel for final approval of the development plan, which we received in January 2019, and have progressed capital investment within this field, including laying subsea equipment for future tie-in of field production into existing Tamar infrastructure. Other than the Tamar Southwest PUDs, we expect all of our international PUDs, including the 551 MMBoe associated with the initial phase of development of the Leviathan field, to be converted to proved developed reserves within five years of initial recognition.
Development Costs   Costs incurred to convert PUDs to proved developed reserves were approximately $1.0 billion in 2018, $1.2 billion in 2017, and $656 million in 2016. Costs incurred in 2018 primarily related to the DJ Basin and Delaware Basin development projects. In addition, we incurred approximately $646 million and $416 million in 2018 and 2017, respectively, to advance the development of the Leviathan PUDs, which are expected to be converted to proved developed reserves with project start up by the end of 2019.
Estimated future development costs relating to the development of all PUDs are projected to be approximately $2.1 billion in 2019, $1.5 billion in 2020, and $1.1 billion in 2021. Estimated future development costs include capital spending on development projects and PUDs related to development projects will be reclassified to proved developed reserves when production commences.
Drilling Plans   Our long-range development plans will result in the conversion of all PUDs to developed reserves within five years of their initial recognition, with the exception of the previously mentioned Tamar Southwest PUDs. PUDs associated with the Tamar Southwest field are expected to be converted to proved developed reserves prior to the end of 2020 as contemplated in our long-range development plan. Initial production from all PUDs is expected to begin during the years 2019 to 2023.
In accordance with US GAAP, we disclose a standardized measure of discounted future net cash flows related to our proved reserves. In order to standardize the measure, all companies are required to use a 10% discount rate and Securities and Exchange Commission (SEC) pricing rules. This prescribed calculation can result in some PUDs having negative present worth, meaning while these PUDs have positive cash flows, the rate of return is lower than 10%. As of December 31, 2018, we had no PUDs with a negative present worth when discounted at 10%.

6


We consider the economic development of reserves based on our estimates of future pricing, future investments, production and other economic factors that are excluded from the SEC reserves requirements and are committed to developing PUDs within five years of initial recognition. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2019 Capital Investment Program. For further information on our reserves, see Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – E&P – Revenues, Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Critical Accounting Policies and Estimates – Reserves, Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures and Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
Internal Controls Over Reserves Estimates   Our policies and processes regarding internal controls over the recording of reserves estimates require reserves to be in compliance with SEC definitions and guidance and prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. Our internal controls over reserves estimates also include the following:
the Audit Committee of our Board of Directors reviews significant reserves changes on an annual basis;
fields that meet a minimum reserve quantity threshold, which combined represent over 80% of our proved reserves, are audited by Netherland, Sewell & Associates, Inc. (NSAI), a third-party petroleum consulting firm, on an annual basis; and
NSAI is engaged by, and has direct access to, the Audit Committee.

See Third-Party Reserves Audit, below.
Responsibility for compliance in reserves estimation is delegated to our Corporate Reservoir Engineering group. Qualified petroleum engineers in our Houston and Denver offices prepare all reserves estimates for our geographical regions. These reserves estimates are reviewed and approved by management and senior engineering staff with final approval by the Senior Vice President – Corporate Development and certain other members of senior management.
Our Senior Vice President – Corporate Development oversees our corporate business development, strategic planning and reserves departments. He is the technical person primarily responsible for overseeing the preparation of our reserves estimates and the third-party audit of our reserves estimates. He has Bachelor of Science and Master of Science degrees in Petroleum Engineering and over 38 years of industry experience. Since 2008, he has worked with positions of increasing responsibility in engineering, evaluations and business unit management at the Company. The Senior Vice President – Corporate Development reports directly to our Chief Executive Officer.
Technologies Used in Reserves Estimation  The SEC’s reserves rules allow the use of techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that has been field tested and has been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
We used a combination of production and pressure performance, wireline wellbore measurements, simulation studies, offset analogies, seismic data and interpretation, wireline formation tests, geophysical logs and core data to calculate our reserves estimates.
Based on reasonable certainty of reservoir continuity in US onshore formations where we operate, we may record proved reserves associated with wells more than one offset location away from an existing proved producing well. All of our wells drilled that were more than one offset away from a proved producing well at the time of drilling were determined to be economically producible.
Third-Party Reserves Audit   In each of the years 2018, 2017, and 2016, we retained NSAI to perform audits of proved reserves. The reserves audit for 2018 included a detailed review of six of our major US onshore and international fields, which covered approximately 98% of total proved reserves.
In connection with the 2018 reserves audit, NSAI prepared its own estimates of our proved reserves and compared its estimates to those prepared by us. NSAI determined that our estimates of reserves have been prepared in accordance with the definitions and regulations of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4-10(a)(24) of Regulation S-X. NSAI issued an unqualified audit opinion on our proved reserves at December 31, 2018, based upon their evaluation. NSAI concluded that our estimates of proved reserves were, in the aggregate, reasonable and have been prepared in accordance with Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information promulgated by the Society of Petroleum Engineers. NSAI’s report, which should be read in its entirety, is attached as Exhibit 99.1 to this Annual Report on Form 10-K.

7


Sales Volumes, Price and Cost Data  Sales volumes, price and cost data were as follows:
 
 
Sales Volumes (1)
 
Average Sales Price (1)(2)
 
Production 
Cost (3)
 
 
Crude Oil &
Condensate
 
NGLs
 
Natural Gas
 
Crude Oil &
Condensate
 
NGLs
 
Natural Gas
 
Total
 
 
(MBbl)
 
(MBbl)
 
(MMcf)
 
(Per Bbl)
 
(Per Bbl)
 
(Per Mcf)
 
(Per BOE)
Year Ended December 31, 2018
 
 
 
 
 
 
 
 
 
 
 
 
United States (4)
 
 
 
 

 
 
 
 
 
 
 
 
 
 
DJ Basin
 
23,165

 
8,880

 
83,766

 
$
63.06

 
$
25.32

 
$
2.13

 
$
4.53

Other US
 
18,506

 
13,761

 
88,370

 
58.69

 
26.24

 
2.90

 
6.16

Total US
 
41,671

 
22,641

 
172,136

 
$
61.12

 
$
25.88

 
$
2.53

 
$
5.35

Israel (5)
 
113

 

 
86,461

 
$
63.25

 
$

 
$
5.47

 
$
2.30

Equatorial Guinea (6)
 
5,690

 

 
77,767

 
68.53

 

 
0.27

 
5.21

Total Consolidated Operations
 
47,474

 
22,641

 
336,364

 
$
62.01

 
$
25.88

 
$
2.76

 
$
4.78

Equity Investee (7)
 
576

 
1,962

 

 
68.99

 
42.14

 

 

Total
 
48,050

 
24,603

 
336,364

 
$
62.10

 
$
27.18

 
$
2.76

 

Year Ended December 31, 2017
 
 
 
 
 
 
 
 
 
 
 
 
United States (4)
 
 
 
 

 
 
 
 
 
 
 
 
 
 
DJ Basin
 
21,564

 
6,911

 
70,660

 
$
50.20

 
$
25.22

 
$
2.96

 
$
4.46

Marcellus Shale
 
233

 
1,654

 
63,443

 
36.91

 
23.81

 
3.15

 
1.05

Other US
 
18,757

 
12,521

 
87,364

 
48.01

 
22.34

 
2.99

 
6.48

Total US
 
40,554

 
21,086

 
221,467

 
$
49.11

 
$
23.40

 
$
3.02

 
$
4.81

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
130

 

 
96,894

 
$
46.95

 
$

 
$
5.37

 
$
2.02

  Other Israel
 

 

 
2,346

 

 

 
3.56

 

  Total Israel
 
130

 

 
99,240

 
$
46.95

 
$

 
$
5.32

 
$
2.01

Equatorial Guinea (6)
 
6,460

 

 
87,269

 
53.68

 

 
0.27

 
4.30

Total Consolidated Operations
 
47,144

 
21,086

 
407,976

 
$
49.73

 
$
23.40

 
$
3.01

 
$
4.31

Equity Investee (7)
 
662

 
2,162

 

 
55.13

 
38.48

 

 

Total
 
47,806

 
23,248

 
407,976

 
$
49.84

 
$
24.81

 
$
3.01

 

Year Ended December 31, 2016
 
 

 
 
 
 

 
 

 
 
 
 

United States (4)
 
 

 
 

 
 
 
 

 
 

 
 
 
 

DJ Basin
 
20,342

 
7,651

 
82,431

 
$
40.85

 
$
14.66

 
$
2.80

 
$
3.99

Marcellus Shale
 
431

 
3,094

 
177,872

 
28.25

 
16.34

 
1.68

 
0.90

Other US
 
15,572

 
9,087

 
62,017

 
38.26

 
14.65

 
2.42

 
6.65

Total US
 
36,345

 
19,832

 
322,320

 
$
39.59

 
$
14.92

 
$
2.11

 
$
3.74

Israel
 
 
 
 
 
 
 
 
 
 
 
 
 
 
  Tamar Field
 
140

 

 
102,280

 
$
36.67

 
$

 
$
5.22

 
$
2.58

  Other Israel
 

 

 
528

 

 

 
3.20

 

  Total Israel
 
140

 

 
102,808

 
$
36.67

 
$

 
$
5.21

 
$
2.60

Equatorial Guinea (6)
 
9,415

 

 
85,987

 
43.54

 

 
0.27

 
4.40

Total Consolidated Operations
 
45,900

 
19,832

 
511,115

 
$
40.39

 
$
14.92

 
$
2.42

 
$
3.72

Equity Investee (7)
 
629

 
1,993

 

 
45.44

 
26.30

 

 

Total
 
46,529

 
21,825

 
511,115

 
$
40.46

 
$
15.96

 
$
2.42

 


(1) 
The adoption of ASC 606 on January 1, 2018 had a de minimis impact on revenues and production expense for 2018. See Item 8. Financial Statements and Supplementary Data – Note 4. Revenue from Contracts with Customers.
(2) 
Average realized prices do not include gains or losses on commodity derivative instruments. See Item 1A. Risk Factors, Item 7A. Quantitative and Qualitative Disclosures About Market Risk and Item 8. Financial Statements and Supplementary Data – Note 13. Derivative Instruments and Hedging Activities.
(3) 
Average production cost includes oil and gas exploration and production operating costs and workover and repair expense and excludes production and ad valorem taxes, gathering, transportation and processing expense, and other royalty expense.

8


(4) 
Amounts include Gulf of Mexico assets prior to the sale in second quarter 2018 and Marcellus Shale assets prior to the sale in second quarter 2017. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
(5) 
Sales volume reduction from 2017 is due to the sale of a 7.5% interest in the Tamar field.
(6) 
(7) 
Volumes represent sales of condensate and liquefied petroleum gas (LPG) from the LPG plant in Equatorial Guinea.
At December 31, 2018, our operated properties accounted for substantially all of our total production. Being the operator of a property improves our ability to directly influence production levels and the timing of projects, while also enhancing our control over operating expenses and capital expenditures.
Productive Wells  The number of productive crude oil and natural gas wells in which we held an interest at December 31, 2018 were as follows:
 
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 
5,289

 
4,781

 
909

 
842

 
6,198

 
5,623

Israel
 

 

 
7

 
2

 
7

 
2

Equatorial Guinea
 
5

 
2

 
23

 
8

 
28

 
10

Total
 
5,294

 
4,783

 
939

 
852

 
6,233

 
5,635

 
Productive wells are producing wells and wells mechanically capable of production. A gross well is a well in which a working interest is owned. The number of net wells is the sum of the fractional working interests owned in gross wells expressed as whole numbers and fractions thereof. Wells with multiple completions are counted as one well in the table above. Gross crude oil and natural gas wells include 711 wells with multiple completions, meaning completions into more than one productive zone.
Developed and Undeveloped Acreage  Developed and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 2018 were as follows: 
 
 
Developed Acreage
 
Undeveloped Acreage
(thousands of acres)
 
Gross
 
Net
 
Gross
 
Net
United States
 
 
 
 
 
 
 
 
Onshore
 
549

 
449

 
527

 
384

Offshore
 
14

 
5

 
6

 
3

Total United States
 
563

 
454

 
533

 
387

International
 
 

 
 

 
 

 
 

Israel (1)
 
185

 
74

 
284

 
111

Equatorial Guinea 
 
284

 
118

 
81

 
30

Newfoundland, Canada
 

 

 
2,332

 
681

Gabon
 

 

 
671

 
403

Cyprus
 

 

 
95

 
33

Cameroon
 

 

 
168

 
168

Total International
 
469

 
192

 
3,631

 
1,426

Total
 
1,032

 
646

 
4,164

 
1,813

(1) Includes 99,000 gross (47,000 net) undeveloped acres for the Alon D license, which we are in the process of relinquishing.
Developed acreage is comprised of leased acres that are within an area spaced by or assignable to a productive well. Undeveloped acreage is comprised of leased acres with defined remaining terms and not within an area spaced by or assignable to a productive well. A gross acre is any leased acre in which a working interest is owned. A net acre is comprised of the total of the owned working interest(s) in a gross acre expressed in a fractional format. 
The above table includes certain undeveloped acreage that is set to expire if production is not established or we take no other action to extend the terms of the leases, licenses, or concessions within a specified period of time. Approximately 91,000, 86,000 and 57,000 net undeveloped acres will expire in 2019, 2020, and 2021, respectively. As of December 31, 2018, approximately 20% of our US onshore undeveloped net acres and 25% of our undeveloped net acres in Israel are set to expire in the next three years. As of December 31, 2018, there are no PUDs associated with this acreage.

9


Drilling Activity  The results of crude oil and natural gas wells drilled and completed for each of the last three years were as follows:
 
 
Net Exploratory Wells
 
Net Development Wells
 
 
 
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
 
Total
Year Ended December 31, 2018
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 

 

 

 
203.0

 

 
203.0

 
203.0

Total
 

 

 

 
203.0

 

 
203.0

 
203.0

Year Ended December 31, 2017
 
 
 
 
 
 
 
 

 
 
 
 
 
 
United States
 

 

 

 
185.3

 

 
185.3

 
185.3

Israel
 

 

 

 
0.3

 

 
0.3

 
0.3

Suriname
 

 
0.2

 
0.2

 

 

 

 
0.2

Total
 

 
0.2


0.2


185.6




185.6


185.8

Year Ended December 31, 2016
 
 
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
0.4

 
0.5

 
0.9

 
156.7

 

 
156.7

 
157.6

Total
 
0.4

 
0.5

 
0.9

 
156.7

 

 
156.7

 
157.6

In addition to the wells drilled and completed in 2018 included in the table above, wells that were in the process of drilling or completing at December 31, 2018 were as follows: 
 
 
Exploratory(1)
 
Development(1)
 
Total
 
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
 

 

 
114.0

 
107.1

 
114.0

 
107.1

Israel (2)
 

 

 
4.0

 
1.6

 
4.0

 
1.6

Total
 

 

 
118.0

 
108.7

 
118.0

 
108.7

(1) 
Amounts exclude wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
(2) 
Includes Leviathan 3, 4, 5 and 7 development wells not yet capable of production. Excludes Tamar Southwest well as it is not in the process of drilling or completing at December 31, 2018.
See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs for additional information on suspended exploratory wells.
Oil and Gas Exploration and Production - Properties and Activities
United States
We have been engaged in crude oil, NGL and natural gas exploration and development activities throughout US onshore since 1932. US operations accounted for 74% of 2018 total consolidated sales volumes and 52% of total proved reserves at December 31, 2018. Approximately 42% of the proved reserves in the US are crude oil and condensate, 32% are natural gas and 26% are NGLs. In second quarter 2018, we exited the Gulf of Mexico through sale of our properties.

10


US Onshore
Our US onshore operations are located in proven basins with long-life production profiles. These assets provide low production-risk drilling opportunities in liquids-rich areas that offer predictable and long-term production and cash flow growth at attractive financial returns. In addition, we evaluate and consider other US onshore new venture prospects to complement our portfolio. Locations of our US onshore operations as of December 31, 2018 are shown on the map below:
USONSHORE.JPG
DJ Basin Our operations in the DJ Basin represent a key asset within our US onshore asset portfolio. As of December 31, 2018, we held approximately 342,000 net acres in the DJ Basin and had proved reserves of 586 MMBoe. Total sales volumes for 2018 were 126 MBoe/d.
2018 Activity In 2018, we focused our drilling and development activity in all three of our main IDP areas, including Mustang, Wells Ranch and East Pony. Our IDP approach has provided an opportunity to efficiently and economically drive production growth by leveraging infrastructure for crude oil, natural gas, and water, including both fresh and produced water assets.
Operationally, our focus on obtaining better results from enhanced completions has led to stronger new well performance. In the Mustang IDP area, our large, contiguous acreage position allows us to focus on row development concepts, which unlike single-pad development, include sequencing operations across a row to more efficiently develop our acreage.
In the Wells Ranch and Mustang IDP areas, we executed acreage trades which add to our contiguous acreage positions and further allow us to control the pace of development and capital investment. During the year, we completed 99 wells and commenced production on 106 wells. We also participated in approximately two non-operated development wells during 2018. As we continue to manage our portfolio, we executed and closed the sale of certain assets in the Greeley Crescent area in 2018 receiving aggregate proceeds of $68 million. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
During 2018, we received approval from Colorado regulators of a Comprehensive Drilling Plan (CDP), the first large-scale CDP approved in the State of Colorado. The CDP spans a 100 square mile position over approximately 64,000 net acres in the Mustang IDP area. With primary operatorship over the acreage, we have the opportunity to control the pace of development and to utilize shared facilities and infrastructure, which is expected to reduce trucking and surface access. As part of the CDP, the permitting process has been clarified and the expiration term for a majority of awarded permits is six years, an increase from the previous two years. We have received permits for over 400 locations across the Mustang IDP area.
Delaware Basin (Permian Basin) Our Delaware Basin position was significantly transformed in 2017 with the closing of the Clayton Williams Energy Acquisition, adding 71,000 highly contiguous net acres in the core of the Delaware Basin adjacent to our Reeves County holdings. As of December 31, 2018, we held approximately 108,000 net acres in the Delaware Basin and had proved reserves of 258 MMBoe. Total sales volumes for 2018 were 53 MBoe/d.
2018 Activity In 2018, we continued execution of the Delaware Basin IDP with a focus on lateral length, pad drilling, multi-zone completions and infrastructure development. We transitioned to a row development concept consistent with our strategy in our other US onshore plays. The transition allows for the focusing of development around existing central gathering facilities

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(CGFs). In late 2018, we moderated our completion activity in the basin to align with economic and available takeaway capacity.
During the year, we completed 70 wells and commenced production on 72 wells. We also participated in approximately 20 non-operated wells during 2018. In addition, we began flowing production to three newly constructed CGFs, an increase from two CGFs in 2017, operated by Noble Midstream Partners.
We utilize the Advantage Pipeline (defined below), which is 50% owned by Noble Midstream Partners, for a portion of our crude oil takeaway. Additionally, we have supplemented our Delaware Basin takeaway position with a firm sales agreement which brings our crude oil to the Texas Gulf Coast. The five-year agreement provides for firm gross sales of at least 10 MBbl/d of crude oil beginning in July 2018, which increased to 20 MBbl/d beginning in October 2018 and for the remainder of the agreement. Currently, crude oil sold under the agreement utilizes the buyer's existing firm transport capacity to Corpus Christi, Texas. Once the EPIC Crude Oil Pipeline is fully in service, we will utilize our own firm transport on the EPIC pipeline, discussed below, to deliver volumes to the buyer in Corpus Christi, Texas. We also have a firm sales agreement for gross crude oil volumes of 5 MBbl/d for 2019.
Also during 2018, we dedicated substantially all of our Delaware Basin acreage position in Reeves County, Texas to the EPIC Crude Oil Pipeline for firm transport of up to 100 MBbl/d, gross, of crude oil from the Delaware Basin to Corpus Christi, Texas, for a 10-year period beginning at pipeline start-up. EPIC announced that it will provide early access to oil pipeline transportation through its Y-Grade Pipeline in third quarter 2019 while the EPIC Crude Oil Pipeline construction continues with in-service expected in first quarter 2020. This strategic agreement is expected to provide long-term flow assurance for our growing crude oil volumes in this area. With this agreement, we have further diversified our US onshore marketing outlets with access to the Texas Gulf Coast and global markets, at an attractive pipeline transport cost.
As part of the EPIC strategic relationship, in first quarter 2019, we assigned Noble Midstream Partners our option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, and Noble Midstream Partners subsequently exercised this option with EPIC. Closing of Noble Midstream Partners’ equity interest in the EPIC Crude Oil Pipeline is anticipated in first quarter 2019 and subject to certain conditions precedent. Concurrently, Noble Midstream Partners exercised and closed its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade pipeline. Cash consideration is expected to total approximately $330 million to $350 million for the interest in the EPIC Crude Oil Pipeline and approximately $165 million to $180 million for the interest in the EPIC Y-Grade Pipeline. Noble Midstream Partners intends to fund the equity investments with its revolving credit facility and/or additional sources of funding. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Eagle Ford Shale As of December 31, 2018, we held approximately 35,000 net acres located in Webb and Dimmit counties and had proved reserves of 158 MMBoe. Total sales volumes for 2018 were 69 MBoe/d. Since acquiring these assets, we have continued to apply IDP learnings and enhancements to optimize development of these assets, including optimizing drilling and completion designs to increase investment efficiency. We have also focused on testing co-development of both the Upper and Lower Eagle Ford formation zones.
2018 Activity Our 2018 capital program was primarily focused within the Upper and Lower Eagle Ford formation zones where we completed 20 wells and commenced production on 13 wells. All wells drilled during 2018 were on multi-well pads leveraging centralized infrastructure. In addition, we continued construction of a central delivery facility in the northern area of Gates Ranch which will provide separation and compression capabilities for our multi-well completion program which began in fourth quarter 2018 and will continue into 2019.
Onshore Exploration Activity In 2018, we captured over 100,000 net acres through undeveloped leasehold acquisition activity in the US onshore. In 2019, we expect to perform additional geologic studies and conduct permitting activities.
US Offshore
In second quarter 2018, we closed the sale of our Gulf of Mexico assets, receiving net proceeds of $384 million and recorded a loss on sale of $24 million. Average annual sales volumes for 2018 were 7 MBoe/d. Proved reserves associated with these properties totaled 23 MMBoe. The divestment enables us to further focus our organization on our highest-return areas that are expected to deliver production and cash flow growth.

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International
Our international business focuses on offshore opportunities in a number of countries and diversifies our portfolio. Development projects in the Eastern Mediterranean and West Africa have contributed substantially to our production and cash flow growth over the last decade. Previous exploration successes in these areas have also identified multiple major development projects that have the potential to contribute to long-term production and cash flow growth in the future.
During 2018, we progressed development of offshore Israel assets primarily through the continued development of Leviathan, where first natural gas sales are anticipated by the end of 2019. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by executing natural gas sales and purchase agreements (GSPAs) for the Leviathan and Tamar fields, offshore Israel, and continue efforts to monetize our significant natural gas discoveries offshore West Africa.
Operations in Equatorial Guinea, Cameroon, Gabon, and Cyprus are conducted in accordance with the terms of Production Sharing Contracts (PSCs). Operations in Israel, Newfoundland (Canada) and other foreign locations are conducted in accordance with concession agreements, permits or licenses. See Item 1A. Risk Factors.
Eastern Mediterranean (Israel and Cyprus)   One of our operating areas is the Eastern Mediterranean, where we have identified the existence of substantial natural gas resources since we obtained our first exploration license in 1998.
Israel, our only producing country in our Eastern Mediterranean area, contributed an average of 239 MMcfe/d, net, of natural gas sales volumes in 2018, representing approximately 12% of total consolidated sales volumes, primarily from the Tamar field. As of December 31, 2018, we had 830 MMBoe of proved reserves in Israel, which represents approximately 43% of total proved reserves. Reserves include proved undeveloped reserves associated with the Leviathan field development. Our leasehold position in the Eastern Mediterranean at December 31, 2018, included six leases and one license operated offshore Israel. In offshore Cyprus, we operate under the terms of a PSC.
At December 31, 2018, the Eastern Mediterranean position included approximately 74,000 net developed acres and 111,000 net undeveloped acres located between 10 and 90 miles offshore Israel in water depths ranging from 700 feet to 6,500 feet. Approximately 47,000 of the 111,000 net undeveloped acres relate to the Alon D license, which we are in the process of relinquishing. The license offshore Cyprus covers approximately 33,000 net undeveloped acres adjacent to our offshore Israel acreage.
Locations of our operations in the Eastern Mediterranean as of December 31, 2018 are shown below:
EMEDMAPA12.JPG

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Offshore Israel Noble Energy and our partners have delivered reliable and affordable natural gas to Israeli customers for over a decade. During this time, we have delivered approximately 2.65 Tcf, gross, of natural gas to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in the country.
We are the first company to construct, operate and produce from a major energy development project offshore Israel. Our Mari-B discovery provided the country with its first supply of domestic natural gas in 2004. In 2009, we discovered the Tamar field, another substantial natural gas resource. To maintain and increase natural gas supply to Israel, we developed the Tamar field with a discovery to production cycle time of approximately four years, which is exceptionally fast by global industry standards for an offshore natural gas project of this magnitude and complexity.
In 2010, we discovered the Leviathan field, our largest natural gas discovery to date. The quantity of discovered natural gas resources at Tamar and Leviathan positions Israel to meet domestic needs for decades and to become a significant natural gas exporter. Multiple natural gas customers exist in the region, and Israel’s domestic demand is predicted to continue to grow over the next decade, primarily driven by increased use of natural gas over coal to fuel electric power generation. During 2018, increased demand for electricity, continued coal displacement and almost 100% asset uptime, enabled us to set a new Tamar cumulative sales volume record of 1.75 Tcf gross. As customer demand increases and to reinforce the reliability of the Tamar project, we have continued to progress regulatory approval with the Government of Israel regarding the development plan for our 2013 Tamar Southwest discovery.
In addition to our natural gas discoveries, the Levant Basin is prospective for crude oil at greater depths. We conducted preliminary exploration activities in 2012 and, in 2018, continued analysis of potential for future exploration. See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Domestic Natural Gas Demand As the Israeli economy continues to grow, the demand for natural gas used primarily for electricity generation is also expected to grow. Demand for natural gas in the industrial sector, including refineries, chemical, desalination, cement and other plants, as well as residential uses, is also increasing. These sectors are gaining confidence that a long-term supply of affordable natural gas will be available and are now investing the capital necessary to convert facilities and infrastructure to use natural gas. In addition, government requirements for emissions reductions have also driven incremental demand for natural gas beginning in 2016. We have executed numerous GSPAs with domestic customers. See Delivery Commitments – Israel Agreements.
Regional Natural Gas Demand and Exports The Eastern Mediterranean presents an opportunity to match our affordable, abundant supply of natural gas with a substantially undersupplied regional market, including customers in Jordan and Egypt. With the Tamar field online providing reliable production, and the development of the Leviathan field progressing, we are well positioned to supply natural gas to the region for many years. In first quarter 2018, we announced the execution of certain agreements to supply natural gas from the Leviathan and Tamar fields to customers in Egypt. See GSPAs and Transportation Agreements for Israeli Export, below.
Tamar Natural Gas Project (25% operated working interest) The Tamar project began production in March 2013 and has peak flow rates of approximately 1.1 Bcf/d, gross. In 2015, we completed the Tamar compression project, which expanded field production capacity by adding compression at the Ashdod onshore terminal (AOT). In 2017, we installed subsea equipment to connect the Tamar 8 development well to the Tamar subsea system. Additionally, in 2017 we completed and commenced production from the Tamar 8 development well, which increases supply reliability as domestic demand for natural gas continues to grow.
In January 2019, the Petroleum Commissioner approved the development plan associated with our 2013 Tamar Southwest discovery, which includes the drilling of an additional development well to reinforce the reliability for the Tamar project and support increased customer demand.
We are also assessing the possibility for expansion of the Tamar project. The project could expand field deliverability from the current capacity level of approximately 1.2 Bcf/d up to approximately 2.1 Bcf/d, a quantity that could allow for additional regional export. Expansion options could include additional investments in pipelines, wells and platform upgrades. Timing of project sanction is dependent upon progress relating to domestic and regional marketing efforts of these resources as well as regulatory approvals from respective governments and capital allocation management.
The Israel Natural Gas Framework (Framework) provided for the reduction in our ownership interest in the Tamar field from 36% to 25% by year-end 2021. We completed the sell-down through a series of transactions, whereby we divested 3.5% of our interest in 2016, and in March 2018, we closed the sale of a 7.5% working interest in Tamar field to Tamar Petroleum Ltd (TASE: TMRP). Proved reserves related to the 7.5% interest sold total 502 Bcf, or approximately 84 MMBoe. In 2018, we also subsequently sold our investment in TMRP shares. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.

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Leviathan Natural Gas Project (39.66% operated working interest)   In early 2017, we announced project sanction of phase 1 of the Leviathan natural gas project and recorded initial proved reserves of 3.3 Tcf (551 MMBoe) associated with the first phase of development. The first phase of development of the Leviathan field provides 1.2 Bcf/d of production capacity and consists of four wells, a subsea production system and a shallow-water processing platform, with a connection to an onshore valve station and the Israel Natural Gas Lines (INGL) pipeline network.
We expect our share of development costs to total approximately $1.5 billion and remaining costs will be funded from our share of cash flows from the Tamar asset. As we progress through the initial phase of development, we have included volume capacity expansion optionality on the Leviathan platform to allow for cost effective expansion to meet growing regional natural gas demand.
As of December 31, 2018, the project is approximately 75% complete and remains on budget and on schedule. During 2018, we installed the in-field gathering and export pipelines, completed installation of all subsea trees, finished completions on all four wells with successful flowbacks, completed the float of the main decks and jacket rollup, flowline installation and completed jacket fabrication and sail-away. Project start up is anticipated by the end of 2019.
We are actively engaged in natural gas marketing activities to fill Leviathan Phase 1 capacity and have progressed multiple GSPAs with initial contracted quantities during 2020-2022 of up to approximately 922 MMcf/d, gross (approximately 320 MMcf/d, net) as of December 31, 2018 to supply customers in Israel, Jordan and Egypt.
GSPAs and Transportation Agreements for Israeli Export   We have entered into a GSPA for the sale of 1.6 Tcf, gross (555 Bcf, net), of natural gas from the Leviathan field to the National Electric Power Company Ltd. (NEPCO) of Jordan, with pricing terms indexed to Brent crude oil. The agreement provides for sales of natural gas intended for consumption in power production facilities over a 15-year period. Sales to NEPCO are anticipated to commence at field startup.
In first quarter 2018, we executed two independent GSPAs for the sale of 2.3 Tcf, gross (651 Bcf, net), of natural gas from the Leviathan and Tamar fields to Dolphinus Holdings Limited to supply natural gas in Egypt. Sales volumes under the GSPA associated with the Leviathan field are anticipated to begin at a firm rate of approximately 350 MMcf/d, gross (approximately 121 MMcf/d, net), at the startup of the Leviathan project. For the Tamar agreement, sales volumes are anticipated to begin at an interruptible rate of up to 350 MMcf/d, gross (approximately 77 MMcf/d, net), dependent upon gas availability beyond existing customer obligations in Israel and Jordan. The GSPA includes an option to convert the Tamar interruptible quantity to a firm-basis with a take or pay commitment. Both contracts are for a 10-year term and have pricing terms indexed to Brent crude oil, similar to other export contracts in the region. The GSPAs are subject to satisfaction of conditions precedent, including regulatory approvals and licenses, and finalizing natural gas transportation agreements. 
In September 2018, we announced the execution, along with certain third-parties, of agreements to support delivery of natural gas into Egypt. With certain partners, we plan to acquire a 39% equity interest in Eastern Mediterranean Gas Company S.A.E., which owns the EMG Pipeline. We will own an effective, indirect interest of approximately 10% net in the pipeline and, along with our partners, will enter into an agreement to exclusively operate the pipeline, securing access to the pipeline's full capacity. Closing of the agreement is subject to fulfillment of certain conditions precedent, which is expected in the first half of 2019, and our portion of estimated acquisition costs is approximately $200 million, net. Technical evaluation and flow reversal activities are currently underway.
We also received a letter of intent from the owner of the Aqaba-El Arish Pipeline to secure an option for additional capacity to transport natural gas within Egypt. This agreement will support transportation of natural gas to Egypt in addition to quantities supplied through the EMG Pipeline.
Alon D License In August 2017, the Petroleum Commissioner of Israel granted us a 32-month extension of the Alon D license (47.059% operated working interest) to drill an exploration well. As of December 31, 2018, we are in the process of relinquishing the license.
Dalit Discovery   Our development plan for the Dalit field (25% operated working interest), a 2009 natural gas discovery, was approved by the Government of Israel. Development includes a tieback to the Tamar platform. We are also analyzing 3D seismic data to evaluate the additional potential of the area, including the possible existence of hydrocarbons at deeper intervals. 
Israel Natural Gas Framework and Regulatory Environment We are subject to certain fiscal, antitrust and other regulatory challenges in Israel. These challenges have been addressed with the enactment of the Framework by the Government of Israel. See Regulations – Israel Regulatory Environment and Item 1A. Risk FactorsOur Eastern Mediterranean discoveries bear certain technical, geopolitical, regulatory, and financial challenges that could adversely impact our ability to monetize these natural gas assets.
Cyprus Natural Gas Project (Offshore Cyprus) We continue to work with the Government of Cyprus on a plan of development for the Aphrodite field that, as currently planned, would deliver natural gas to regional customers. In addition, we

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are focused on capital cost improvements, as well as natural gas marketing efforts and execution of natural gas sales and purchase agreements, which, once secured, will progress the project to a final investment decision.
West Africa (Equatorial Guinea, Cameroon and Gabon)   West Africa includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo PSC, offshore Cameroon, and one block offshore Gabon. In West Africa, our interests can be burdened by overriding royalty interests and/or other government interests. As such, our working interests may differ from our revenue interests. Equatorial Guinea is currently the only producing country in our West Africa segment and, excluding the impact of equity investees, Equatorial Guinea contributed an average of 51 MBoe/d of sales volumes in 2018 and represented approximately 15% of total consolidated sales volumes. At December 31, 2018, Equatorial Guinea had proved reserves of 97 MMBoe, which represents approximately 5% of total proved reserves. No wells were completed or participated in during the year.
Locations of our upstream operations in West Africa, as of December 31, 2018 are shown on the map below:
WESTAFRICAMAPA02.JPG
Aseng Field Aseng is an oil field on Block I (40% operated working interest, 38% revenue interest), offshore Equatorial Guinea, which began producing in 2011. The development includes five horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until sold, and natural gas and water are reinjected into the reservoir to maintain pressure and maximize crude oil recoveries. During 2018, sales volumes from the Aseng field averaged 6 MBbl/d, net.
The Aseng FPSO is designed to act as a crude oil production hub, as well as a liquids storage and offloading facility, with capabilities to support future subsea oil field developments in the area. It also has the ability to process and store condensate from natural gas condensate fields in the area, the first of which is Alen. Since it first came online, the Aseng field has maintained reliable performance, averaging almost 100% production uptime and, as of December 31, 2018, has produced over 95 MMBbls of cumulative gross crude oil production.
In late 2018, we submitted a plan of development to the Government of Equatorial Guinea for the drilling of an additional crude oil development well. The well would be tied into existing subsea infrastructure and is expected to add crude oil reserves, minimize field declines and extend the reservoir life of the Aseng field. We expect to sanction the project in the near future with first oil anticipated in late 2019.
Alen Field   Alen is a natural gas and condensate field primarily on Block O (51% operated working interest, 45% revenue interest), offshore Equatorial Guinea, which includes three production wells and three natural gas injection wells connected to a production platform. Condensate is pumped to the Aseng FPSO for storage and offloading. Alen has been producing since 2013 and sales volumes averaged approximately 2 MBbl/d, net, during 2018. As of December 31, 2018, Alen has produced over 36 MMBbls of cumulative gross condensate production. The Alen platform is expected to be utilized in our natural gas monetization efforts. See West Africa Natural Gas Monetization, below.
Alba Field   Alba is a natural gas and condensate field located offshore Equatorial Guinea (33% non-operated working interest, 32% revenue interest), which has been producing since 1991. Operations include the Alba field and related production and condensate storage facilities, a LPG processing plant where additional condensate is extracted along with LPGs, and a methanol plant capable of producing up to 3,100 gross metric tons per day of methanol. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2018, Alba field sales volumes averaged 50 MBoe/d, net, reflecting 43 MBoe/d attributable to total sales volumes and 7 MBoe/d attributable to an equity investee.

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We sell our share of primary condensate produced in the Alba field under short-term contracts at market-based prices. We sell our share of natural gas production from the Alba field to the LPG plant, the methanol plant, an unaffiliated liquefied natural gas (LNG) plant and a power generation plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. The methanol plant is owned by Atlantic Methanol Production Company, LLC (AMPCO), in which we have a 45% interest. AMPCO purchases natural gas from the Alba field under a contract that runs through 2026 and subsequently markets the produced methanol primarily to customers in the US and Europe. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices.
We account for both Alba Plant and AMPCO as equity method investments and present our share of income as a component of revenues. See Item 8. Financial Statements and Supplementary Data – Note 15. Equity Method Investments.
West Africa Natural Gas Monetization   We continue efforts to monetize our significant natural gas discoveries offshore West Africa (YoYo, Yolanda and Felicita).
A natural gas development team has been working with local governments to evaluate natural gas monetization development plans and progress negotiations of required contracts. In May 2018, we announced the execution, along with the Government of the Republic of Equatorial Guinea and necessary third-parties, of a Heads of Agreement establishing the framework for development of natural gas from the Alen field. The agreement outlines the high-level commercial terms for Alen natural gas to be processed through Alba Plant and Equatorial Guinea LNG Holdings Limited’s LNG plant. Both plants are located in Punta Europa. The contemplated structure would result in Alen natural gas being marketed to global LNG customers. Sanction of the project is contingent upon final commercial agreements being executed.
Existing production and processing facilities in place at the Alen platform and in Punta Europa require certain modifications to produce and process the Alen natural gas. The agreement contemplates construction of a 65-kilometer pipeline to transport natural gas from the Alen platform to the facilities in Punta Europa. We have awarded front-end engineering design (FEED) activities to progress the project to final investment decision, which is planned for 2019 with first gas anticipated in 2021.
Offshore Cameroon We have an interest in the YoYo PSC (100% operated working interest). The YoYo-1 exploratory well was drilled in 2007, discovering natural gas and condensate. We are working with the government of Cameroon to evaluate natural gas development options, which will provide a more robust framework directly related to oil and gas operational activities.
Offshore Gabon We are the operator of Block Doukou Dak (60% working interest), an undeveloped, deepwater area. Our exploration commitment includes an obligation for 3D seismic, which was acquired and processed throughout 2016 and the first half of 2017. We received the final product mid-year 2017 and are currently evaluating the seismic data results.
See also Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Other International Other international operations include the following:
Offshore Newfoundland (Canada) We have a non-operated 25% working interest in exploration licenses (EL) EL1145, EL 1146 and EL 1148, and a non-operated 40% working interest in EL 1149. BP Canada Energy Group ULC is the operator of the blocks. We licensed 3D seismic data to help us assess the economic viability of numerous exploration leads and prospects.
Offshore Suriname  In October 2017, our partner spud the Araku-1 exploration well in Block 54 offshore in the Atlantic Ocean and subsequently plugged and abandoned the well. As a result, we recorded dry hole expense of $7 million in 2017. Based upon well results, modeling of the basin and review of further prospectivity, we released our non-operated 20% working interest and no longer have acreage offshore Suriname as of December 31, 2018.
Offshore Falkland Islands In 2016, following completion of our geological assessment, we exited all licenses, excluding the PL-001, which contained the Rhea prospect, and recorded $25 million of undeveloped leasehold impairment expense. In fourth quarter 2018, we provided notice to the Falklands government and exited our remaining license. As of December 31, 2018, we no longer have acreage offshore Falkland Islands.
North Sea  The non-operated MacCulloch field is currently undergoing decommissioning activities. Due to its size and location, field abandonment is a multi-year process, requiring several phases. Therefore, our share of estimated field abandonment costs, recorded as an asset retirement obligation (ARO), may change over time.
Midstream – Properties and Activities
We continue to develop our Midstream segment, which includes gathering, treating, and transportation assets, as well as water-related infrastructure, including fresh water delivery and produced water disposal assets. Our Midstream assets are strategically located with our development and production activities in the DJ and Delaware Basins and provide services to us and other third-party customers.
Noble Midstream Partners Our Midstream operations include those of Noble Midstream Partners, a publicly traded, consolidated subsidiary and limited partnership that constructs and operates a wide range of domestic midstream infrastructure

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assets. Noble Midstream Partners is a fee-based, growth-oriented Delaware master limited partnership formed in December 2014 organized in a development company structure. On September 20, 2016, Noble Midstream Partners completed its initial public offering of common units, which provided Noble Midstream Partners access to the capital markets to support funding of its US onshore midstream investment program. At December 31, 2018, our ownership interest in Noble Midstream Partners consisted of a 45.4% limited partner interest, the entire non-economic general partner interest, and all incentive distribution rights.
In addition to developing and operating midstream assets, Noble Midstream Partners leveraged its existing dedications and commercial relationships through investing in certain partnerships providing transportation services downstream of our current operations. As of December 31, 2018, Noble Midstream Partners has a 50% interest in Advantage Pipeline L.L.C. (Advantage Pipeline) in the Delaware Basin and a 3.33% interest in White Cliffs Pipeline L.L.C. (White Cliffs) in the DJ Basin. In first quarter 2019, we assigned Noble Midstream Partners our option to acquire a 30% equity interest in the EPIC Crude Oil Pipeline, and Noble Midstream Partners subsequently exercised this option with EPIC. Closing of Noble Midstream Partners’ equity interest in the EPIC Crude Oil Pipeline is anticipated in first quarter 2019 and subject to certain conditions precedent. Concurrently, Noble Midstream Partners exercised and closed its option with EPIC to acquire a 15% equity interest in the EPIC Y-Grade Pipeline. Cash consideration is expected to total approximately $330 million to $350 million for the interest in the EPIC Crude Oil Pipeline and approximately $165 million to $180 million for the interest in the EPIC Y-Grade Pipeline. Noble Midstream Partners intends to fund the equity investments with its revolving credit facility and/or additional sources of funding. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
The following diagram depicts our organizational structure as of December 31, 2018. Development companies identified in red and blue indicate the location of the assets as either in the DJ or Delaware Basin, respectively.
NBLXORGUPDATEDNEW2.JPG

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Major Construction Projects Activity in 2018 primarily focused on construction and development of midstream infrastructure assets, including:
completed construction of the Collier, Billy Miner Train II and Coronado CGFs in the Delaware Basin;
completed construction of freshwater delivery infrastructure and commenced gathering services in the DJ Basin; and
signed a non-binding letter of intent with Salt Creek Midstream LLC (Salt Creek) for construction of a crude oil pipeline system in the Delaware Basin, for which definitive agreements with Salt Creek were executed in February 2019.
In 2019, we expect our midstream investment to continue to focus on the DJ and Delaware Basins to meet the needs of our upstream operations and third-party customers.
Noble Midstream Partners Saddle Butte Acquisition On January 31, 2018, Noble Midstream Partners acquired a 54.4% interest in Black Diamond Gathering LLC (Black Diamond), an entity formed by Black Diamond Gathering Holdings LLC, a wholly-owned subsidiary of Noble Midstream Partners, and Greenfield Midstream, LLC (Greenfield), which completed the acquisition of Saddle Butte from Saddle Butte Pipeline II, LLC (Saddle Butte Acquisition). Saddle Butte owned a large-scale integrated gathering system, located in the DJ Basin, which we subsequently renamed the Black Diamond gathering system. In addition to gathering services, certain oil purchases and sales occur within this business to better leverage existing infrastructure as well as to provide additional flexibility to Black Diamond's customer base. Cash consideration totaled $681 million, approximately $343 million of which was funded by Greenfield. Noble Midstream Partners operates the Black Diamond gathering system and we consolidate the entity for financial reporting purposes. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Other Noble Energy Midstream Assets Outside of Noble Midstream Partners and our interests in its development companies, we have retained full ownership in certain midstream businesses. Primarily, we own and operate two natural gas processing plants in the DJ Basin, crude oil gathering assets in the DJ and Delaware Basins, fresh water delivery assets in the Delaware Basin and gathering assets in the Eagle Ford Shale. We have granted rights of first refusal (ROFRs) on a combination of midstream assets retained by us outside of Noble Midstream Partners to provide midstream services on certain acreage and/or to acquire certain midstream assets.
Marcellus Shale CONE Gathering Divestiture In January 2018, we completed the sale of our 50% interest in CONE Gathering LLC (CONE Gathering) to CNX Resources Corporation and received proceeds of $309 million. After the sale, we held 21.7 million common units, representing a 34.1% limited partner interest, in CNX Midstream Partners LP (CNX Midstream Partners, NYSE: CNXM). We sold these units in 2018 receiving net proceeds of $387 million. The investment was previously accounted for under the equity method of accounting. See Item 8. Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Third-Party Customers During 2018, Noble Midstream Partners continued providing crude oil and produced water gathering and fresh water delivery services to unaffiliated third parties in the Greeley Crescent IDP area of the DJ Basin. Additionally, the acquisition of interest in the Saddle Butte system has significantly increased the number of third-party customers across our Midstream segment.
Delivery Commitments 
US Onshore Agreements   Crude oil, NGLs, natural gas and condensate produced in the US onshore are sold under varying contracts, including short-term, long-term or life-of-field contracts where all production from a well or group of wells is sold to one or more customers, at market-based prices adjusted for location and quality. Certain of our sales and delivery agreements may include natural gas processing or NGL fractionation commitments for the volumes delivered, either to a customer or to a service provider as assessed and accounted for under ASC 606.
In addition, we have certain sales and delivery agreements to supply minimum quantities of production to various customers. The majority of our production is sold under short-term contracts. At December 31, 2018, long-term (greater than one year) sales commitments we were contractually committed to deliver included our five-year agreement which brings a portion of our Delaware Basin crude oil to the Texas Gulf Coast. Remaining quantities to be delivered under this agreement are 36.5 MMBbls. We expect to fulfill this delivery commitment with existing proved developed and proved undeveloped reserves, which we regularly monitor to ensure sufficient availability to meet the commitments.
Israel Agreements We currently sell natural gas from the Tamar field primarily to the IEC and numerous other Israeli purchasers, including independent power producers, cogeneration facilities and industrial companies. Most contracts provide for the sale of natural gas over an initial term of one to 18 years. Some of the contracts provide for an increase or reduction in total quantities, and some contracts are interruptible during certain contract periods. Sales prices may be based on an initial base price subject to price indexation over the life of the contract and have a contractual floor. The IEC contract provides for price renegotiation in certain years with limits on the increase/decrease from the contractual price.

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Under the contracts, we and our partners have financial exposure in the event we cannot fully deliver the contract quantities. This exposure is capped by contract and will be reflected as a reduction in sales price to the purchaser for periods in which we are delivering partial contract quantities, or as a direct payment to the customer under certain circumstances and with a cap. The cap is subject to force majeure considerations. We believe that any such sales price adjustments or direct payments would not have a material impact on our earnings or cash flows.
As of December 31, 2018, a total of approximately 4.5 Tcf, gross (1.0 Tcf, net), of natural gas remained to be delivered under our Tamar contracts. As of December 31, 2018, we have recorded 1.5 Tcf, net, of proved natural gas reserves, including proved developed reserves of 1.3 Tcf, net, and PUD reserves of 241 Bcf, net, for the Tamar field. Based on current production levels and future development plans, our available quantities of proved reserves are more than sufficient to meet near-term delivery commitments associated with Tamar sales agreements without further capital investment. In addition, we have also executed certain interruptible GSPAs which would supply natural gas from Tamar.
We have also executed firm natural gas sales agreements for the sale of approximately 2.2 Tcf, gross (0.8 Tcf, net) of natural gas from the Leviathan field to customers in Israel and Jordan. Sales are anticipated to begin at the startup of the Leviathan project, currently projected for the end of 2019. As of December 31, 2018, we have recorded 3.3 Tcf, net, of PUD reserves for the Leviathan field related to sales to Israeli and Jordanian customers. See Eastern Mediterranean (Israel and Cyprus) - GSPAs and Transportation Agreements for Israeli Export.
West Africa Agreements Our share of crude oil and condensate from the Aseng, Alen and Alba fields is sold at market-based prices to Glencore Energy UK Ltd (Glencore Energy) and are transported via tankers. 
Natural gas from the Alba field is sold for $0.25 per MMBtu to a methanol plant, an LPG plant, an unaffiliated LNG plant and a power generation plant. The sales contract with the methanol plant runs through 2026, and the sales contract with the LNG plant runs through 2023. The methanol and LPG plants are owned by affiliated entities accounted for under the equity method.
Significant Purchasers 
BP North American Funding (BP) and Shell Trading (US) (Shell) were the largest single purchasers of our 2018 production. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information.
Transportation Commitments 
We have entered into various long-term firm transportation contracts for some of our US onshore production. We use long-term contracts such as these to provide production flow assurance and ensure access to markets for our products at the best possible price and at the lowest possible logistics cost. These arrangements represent commitments to pay transportation fees, not commitments to deliver minimum volumes to end users.
Our financial commitments under these contracts are included in our contractual obligations disclosures. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual Obligations, Item 8. Financial Statements and Supplementary Data – Note 10. Marcellus Shale Firm Transportation Commitments and – Note 11. Commitments and Contingencies.
Regulations
Exploration for, and development, production and marketing of, crude oil, NGLs and natural gas are extensively regulated at the federal, state, and local levels in the US, and internationally. Regulations affecting the crude oil and natural gas industry are under constant review for amendment or expansion over time and frequently impose more stringent requirements on crude oil and natural gas companies.
Various governmental bodies have issued rules, regulations and orders that require extensive efforts to ensure compliance, that impose incremental costs to comply, and that carry substantial penalties for failure to comply, which may impact our ability to economically produce and sell crude oil, NGLs and natural gas. These issuances may restrict the rate of crude oil, NGL and natural gas production below the rate that would otherwise exist in the absence of such laws, regulations and orders. The regulatory requirements on the crude oil and natural gas industry often result in incremental costs of doing business and consequently affect our profitability. See Item 1A. Risk Factors We are subject to increasing governmental regulations and environmental requirements that may restrict our access to land and/or cause us to incur substantial incremental costs.
Various domestic and international agencies have legal and regulatory authority and oversight over our exploration for, and production and sale of, crude oil, NGLs and natural gas. Internationally, oversight also includes energy-related ministries or other agencies of our host countries, each having certain relevant energy or hydrocarbons laws. Other US federal agencies with certain authority over our business include the Internal Revenue Service (IRS) and the SEC. In addition, we are governed by the rules and regulations of the NYSE, upon which shares of our common stock and common units of Noble Midstream Partners are traded.

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Among the laws affecting our operations are the following:
Environmental Matters We take into account the cost of complying with environmental regulations in planning, designing, drilling, operating, and abandoning wells. In most instances, the regulatory requirements relate to the handling and disposal of drilling and production wastes, water and air pollution control procedures, facility siting and construction, protection of endangered species and habitat, prevention of and responses to leaks and spills, and the remediation of petroleum-product contamination. These laws and regulations may require the acquisition of a permit before drilling commences, restrict the types, quantities and concentrations of various substances that can be released into the environment in connection with drilling and production activities, limit or prohibit construction or drilling activities on certain lands lying within wilderness, habitat to endangered or threatened species, wetlands, ecologically or seismically sensitive areas, and other protected areas, require action to prevent or remediate pollution from current or former operations, such as plugging abandoned wells or closing pits, result in the suspension or revocation of necessary permits, licenses and authorizations, require that additional pollution controls be installed and impose substantial liabilities for pollution resulting from our operations. Where our drilling activities could result in a serious adverse effect upon a protected species, a federal or state agency could order a complete halt to such activities in certain locations or during certain seasons. Consequently, the presence of a protected species in areas where we operate could adversely affect future production from those areas and government agencies frequently add to the lists of protected species.
Under state and federal laws, we could be required to remove or remediate previously disposed wastes, including wastes disposed of or released by us, or by prior owners or operators, in accordance with current laws, to suspend or cease operations in contaminated areas, or to perform remedial well plugging operations or cleanups. The US Environmental Protection Agency (EPA) and various state agencies have limited the disposal options for hazardous and non-hazardous wastes and may continue to do so. The owner and operator of a site, and persons that treated, disposed of, or arranged for the disposal of hazardous substances found at a site, may be liable, without regard to fault or the legality of the original conduct, for the release of a hazardous substance into the environment. The EPA, state environmental agencies and, in some cases, third parties are authorized to take actions in response to threats to human health or the environment and to seek to recover from responsible classes of persons the costs of such action. Moreover, it is not uncommon for neighboring landowners and other third parties to file claims for personal injury and property damage allegedly caused by the release of hazardous substances, hydrocarbons or other waste products into the environment.
Furthermore, certain wastes generated by our crude oil and natural gas operations that are currently exempt from the definition of hazardous waste may in the future be subject to considerably more rigorous and costly operating and disposal requirements. Indeed, legislation has been proposed from time to time in Congress to re-categorize certain oil and natural gas exploration, development and production wastes as “hazardous wastes.” Also, in December 2016, the EPA agreed in a consent decree to review its regulation of oil and gas waste. It has until March 2019 to determine whether any revisions are necessary.
Under federal and state occupational safety and health laws, we must develop and maintain information about hazardous materials used, released, or produced in our operations. Certain portions of this information must be provided to employees, state and local governmental authorities, and local citizens. We are also subject to the requirements and reporting set forth in federal workplace standards. Moreover, certain state or local laws or regulations and common law may impose liabilities in addition to, or restrictions more stringent than, those described herein.
We have made and will continue to make expenditures necessary to comply with environmental requirements. We do not believe that compliance with such requirements will have a material adverse effect on our capital expenditures, earnings or competitive position. Although such requirements do have a substantial impact on the crude oil and natural gas industry, they do not appear to affect us to any greater or lesser extent than other companies in the industry.
Apart from these federal matters, most of the states where we operate have separate authority to regulate operational and environmental matters.  
Colorado The oil and gas industry is regulated in part by the Colorado Oil and Gas Conservation Commission (COGCC). In December 2018, the COGCC approved an increased setback distance for crude oil and natural gas wells and production facilities located in close proximity to schools based on an expanded definition of “school facility.” Previously, the COGCC had allowed uniform setback distances of 500 feet from occupied buildings and 1,000 feet from high occupancy building units. The setback rules also require operators to utilize increased mitigation measures to limit potential drilling impacts and require advance notice to surface owners, owners of occupied building units, and local governments prior to the filing of an Application for Permit to Drill or Oil and Gas Location Assessment.
The COGCC also has implemented rules making Colorado the first state to require sampling of groundwater for hydrocarbons and other indicator compounds both before and after drilling. Further, the COGCC has adopted rules increasing the maximum penalty for violations of its requirements.
The state environmental agency, the Colorado Department of Public Health and Environment (CDPHE), likewise has adopted measures to regulate air emissions, water protection, and waste handling and disposal relating to our crude oil and natural gas

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exploration and production. For air, the CDPHE has extended the EPA’s emissions standards for crude oil and natural gas operations to directly control methane.
In the state of Colorado, we have historically encountered initiatives to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. For example, in November 2018, a majority of Colorado voters voted against Proposition #112, which, if passed, would have significantly limited, or in some cases prevented, the future development of crude oil and natural gas and demand for our midstream services in areas where we currently conduct operations. If similar regulatory measures are adopted, we could incur additional costs to comply with any of its requirements or may experience delays and/or curtailment in the permitting or pursuit of our exploration, development, or production activities. Such compliance costs and delays, curtailments, limitations, or prohibitions could have a material adverse effect on our cash flows, results of operations, financial condition, and liquidity.
It is likely these types of initiatives will continue into the future in Colorado, and efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition. See Item 1A. Risk FactorsWe face various risks associated with the trend toward increased anti-oil and gas development activity.
Some of the counties and municipalities where we operate in Colorado have adopted their own regulations or ordinances that impose additional restrictions on our crude oil and natural gas exploration and production. To date these have not significantly impacted our operations.
In April 2015, we entered into a joint consent decree (Consent Decree) with the EPA, US Department of Justice, and State of Colorado to improve emission control systems at a number of our condensate storage tanks that are part of our upstream crude oil and natural gas operations within the Non-Attainment Area of the DJ Basin. All fines required under the Consent Decree were paid in 2015; however, the required injunctive relief remains ongoing. We have concluded that the penalties, injunctive relief, plugging and abandonment activities, and mitigation expenditures that result from this settlement, based on currently available information, will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 1A. Risk Factors – Our operations require us to comply with a number of US and international laws and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business and Item 8. Financial Statements and Supplementary Data – Note 11. Commitments and Contingencies.
Texas  Texas has regulations governing conservation matters, including provisions for the unitization or pooling of oil and gas properties, the establishment of maximum rates of production from oil and gas wells, the regulation of spacing, and requirements for plugging and abandonment of wells.
The oil and gas industry is regulated in part by the Texas Railroad Commission (RRC). The RRC requires Texas oil and gas operators to disclose on the FracFocus website chemical ingredients and water volumes used in hydraulic fracturing treatments. FracFocus.org is a public registry operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council.
In addition, the RRC maintains a “well integrity rule” that addresses requirements for drilling, casing and cementing wells. The rule also includes testing and reporting requirements, including clarifying that cementing reports must be submitted after well completion or after cessation of drilling, whichever is earlier. Furthermore, the RRC oversees 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. The RRC has used this authority to deny permits for waste disposal wells.
Climate Change In recent years, the EPA has finalized a series of greenhouse gas (GHG) monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. In addition, almost one-half of the states have already taken measures to reduce emissions of GHGs primarily through the development of GHG emission inventories and/or regional GHG cap-and-trade programs.
At the international level, in December 2015, the US signed the Paris Agreement on climate change and pledged to take efforts to reduce GHG emissions and to conserve and enhance sinks and reservoirs of GHGs. The Paris Agreement entered into force in November 2016. However, in August 2017, the US notified the United Nations that it would be withdrawing from the Paris Agreement and begin negotiations to either re-enter or negotiate an entirely new agreement with more favorable terms for the US. The Paris Agreement sets forth a specific exit process, whereby a party may not provide notice of its withdrawal until three years from the effective date, with such withdrawal taking effect one year from such notice. While the US Administration expressed a clear intent to cease implementing the Paris Agreement, it is not clear how it plans to accomplish this goal, whether a new agreement can be negotiated, or what terms would be included in such an agreement. Furthermore, in response to the announcement, many state and local leaders stated their intent to intensify efforts to uphold the commitments set forth in the international accord.

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The current state of development of the ongoing international climate initiatives and any related domestic actions make it difficult to assess the timing or effect on our operations or to predict with certainty the future costs that we may incur in order to comply with future international treaties, legislation or new regulations. However, future restrictions on emissions of GHGs, or related measures to encourage use of renewable energy could have a significant impact on our future operations and reduce demand for our products. See also Item 1A. Risk Factors.
Israel Regulatory Environment The Framework, as adopted by the Government of Israel, provides clarity on numerous matters concerning resource development, including certain fiscal, antitrust and other regulatory matters. The Framework provided for the reduction of our ownership interest in the Tamar and Dalit fields to 25% by year-end 2021, which we completed in 2018, while enabling the marketing of Leviathan natural gas to Israeli customers. See Item Financial Statements and Supplementary Data – Note 5. Acquisitions and Divestitures.
Hydraulic Fracturing 
Hydraulic fracturing techniques have been used for decades on the majority of all new onshore crude oil and natural gas wells drilled domestically. The process involves the injection of water, sand and chemical additives under pressure into targeted subsurface formations to stimulate oil and gas production. We strive to adopt best practices and industry standards and comply with all regulatory requirements regarding well construction and operation. For example, the qualified service companies we use to perform hydraulic fracturing, as well as our personnel, monitor rate and pressure to assure that the services are performed as planned. Our well construction practices include installation of multiple layers of protective steel casing surrounded by cement that are specifically designed and installed to protect freshwater aquifers by preventing the migration of fracturing fluids into those aquifers. To help reduce our operational demand for freshwater and need for disposal, we are currently developing technology and infrastructure to expand our water recycling capacity in the DJ and Delaware Basins. We believe that these processes help ensure hydraulic fracturing is safe and does not and will not pose a risk to water supplies, the environment or public health. 
All of the states where our US onshore operations are located (including Colorado and Texas) have developed hydraulic fracturing regulations. See Regulations - Colorado and Texas. Although hydraulic fracturing is regulated primarily at the state level, both Congress and government agencies at all levels from federal to municipal are studying the potential impacts of hydraulic fracturing, and some agencies have asserted regulatory authority over hydraulic fracturing and/or certain aspects of oil and gas operations connected with the hydraulic fracturing process. Some agencies have implemented new requirements, and some are evaluating the need for additional requirements. For example:
legislation has been proposed in Congress to amend the Safe Drinking Water Act to repeal the exemption for hydraulic fracturing from the definition of “underground injection,” to require federal permitting and regulatory control of hydraulic fracturing, and to require disclosure of the chemical constituents of the fluids used in the fracturing process;
the Bureau of Land Management (BLM), as a result of legal challenges, has published a final rule to rescind its 2015 rule governing hydraulic fracturing on federal and Indian lands. Further legal challenges are expected;
the Occupational Safety and Health Administration (OSHA) has lowered exposure limits for workers who use silica (sand) in hydraulic fracturing activities, and silica work practices have become stricter;
state and federal regulatory agencies have focused on a possible connection between the operation of injection wells used for oil and gas waste disposal and seismic activity, which some have termed “induced seismicity,” and some state regulatory agencies have modified their regulations to account for such induced seismicity; and
ongoing or proposed studies on the environmental impacts of hydraulic fracturing could spur initiatives to further regulate hydraulic fracturing.
We currently disclose information regarding the components and chemicals used in the hydraulic-fracturing process for all US onshore areas in which we operate through the website for the public registry FracFocus.org, which is operated jointly by the Interstate Oil & Gas Compact Commission and the Ground Water Protection Council.
Risk and Insurance Program
As protection against financial loss resulting from many, but not all operating hazards, we maintain insurance coverage, including certain physical damage, business interruption (loss of production income), employer's liability, third-party liability, worker's compensation insurance and certain insurance related to cyber security. We maintain insurance at levels that we believe are appropriate and consistent with industry practice. We regularly review our potential risks of loss and the cost and availability of insurance and the company's ability to sustain uninsured losses, and revise our insurance program accordingly.
Availability of insurance coverage, subject to customary deductibles and recovery limits, for certain perils such as war or political risk is often excluded or limited within property policies. We are, however, actively looking to secure additional coverages for political risks in Jordan and Egypt. In Israel and Equatorial Guinea, we insure against acts of war and terrorism in addition to providing insurance coverage for normal operating hazards facing our business. Additionally, as being part of

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critical national infrastructure, the Israel offshore and onshore assets are included in a special property coverage afforded under the Israeli government's Property Tax and Compensation Fund Law; however, the amount of financial recovery through the fund is not guaranteed.
We have a risk assessment program that analyzes safety and environmental hazards, including cyber threats, and establishes procedures, work practices, training programs and equipment requirements, including monitoring and maintenance rules, for continuous improvement. We also use third-party consultants to help us identify and quantify our risk exposures at major facilities. We have a robust prevention program and continue to manage our risks and operations such that we believe the likelihood of a significant event is remote. However, if an event occurs that is not covered by insurance, not fully protected by insured limits or our non-operating partners are not fully insured, it could have a material adverse impact on our financial condition, results of operations and cash flows. See Item 1A. Risk Factors - The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.
Competition 
The crude oil and natural gas industry is highly competitive. We encounter competition from other crude oil and natural gas companies in all areas of operations, including the acquisition of seismic data and lease rights on crude oil and natural gas properties and for the labor and equipment required for exploration and development of those properties. Our competitors include major integrated crude oil and natural gas companies, state-controlled national oil companies, independent crude oil and natural gas companies, service companies engaging in exploration and production activities, drilling partnership programs, private equity, and individuals. Many of our competitors are large, well-established companies. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. Our ability to acquire additional properties and to discover reserves in the future will be dependent upon our ability to evaluate and select suitable properties and to consummate transactions in a highly competitive environment.
In addition, as we continue to expand our midstream services, we will face a high level of competition, including major integrated crude oil and natural gas companies, interstate and intrastate pipelines, and companies that gather, compress, treat, process, transport, store or market natural gas. As we seek to continue to provide midstream services to additional third party producers, we will also face a high level of competition. Competition is often the greatest in geographic areas experiencing robust drilling by producers and during periods of high commodity prices for crude oil, natural gas or NGLs.
See Item 1A. Risk Factors - We face significant competition and many of our competitors have resources in excess of our available resources.
Employees 
As of December 31, 2018, we had 2,330 full-time employees.
Offices
Our principal corporate office is located at 1001 Noble Energy Way, Houston, Texas, 77070. We maintain additional regional offices in the US, Israel, Cyprus, Egypt, Equatorial Guinea, and Cameroon. 
Title to Properties 
We believe that our title to the various interests set forth above is satisfactory and consistent with generally accepted industry standards, subject to exceptions that would not materially detract from the value of the interests or materially interfere with their use in our operations. Individual properties may be subject to burdens such as royalty, overriding royalty and other outstanding interests customary in the industry. In addition, interests may be subject to obligations or duties under applicable laws or burdens such as production payments, net profits interest, liens incident to operating agreements and for current taxes, development obligations under crude oil and natural gas leases or capital commitments under PSCs or exploration licenses. We have also dedicated certain of our US onshore acreage to Noble Midstream Partners for the provision of midstream services to us.
Furthermore, while our DJ Basin assets are primarily held by production, other assets, such as our Eagle Ford Shale and Delaware Basin properties, are held primarily through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas or exercise options with land owners to extend leases. Failure to meet these obligations may result in the loss of a lease.
Title Defects Subsequent to a lease or fee interest acquisition transaction, the buyer usually has a period of time in which to examine the leases for title defects. Adjustments for title defects are generally made within the terms of the sales agreement, which may provide for arbitration between the buyer and seller.
Conflicts with Surface Rights Mineral rights are property rights that include the right to use land surface that is reasonably necessary to access minerals beneath. Lawsuits regarding conflicts between surface rights and mineral rights are currently

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pending in several states. In several cases, owners of surface rights are suing various companies to prevent companies from using their land surface to drill horizontal wells to explore for or produce hydrocarbons from neighboring mineral tracts. If a plaintiff were to prevail in such a case, it could become more difficult and expensive for a company to place multi-acre well pads and/or limit the length of horizontal wells drilled from a pad.
Available Information
Our website address is www.nblenergy.com. Available on this website under “Investors – Financial Information – SEC Filings,” free of charge, are our annual reports on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, proxy statements, Forms 3, 4 and 5 filed on behalf of directors and executive officers and amendments to those reports as soon as reasonably practicable after such materials are electronically filed with or furnished to the SEC. Alternatively, you may access these reports at the SEC’s website at www.sec.gov.
Also posted on our website under “Our Story – Transparency – Corporate Governance – Committee Charters,” and available in print upon request made by any shareholder to the Investor Relations Department, are charters for our Audit Committee, Compensation, Benefits and Stock Option Committee, Corporate Governance and Nominating Committee, and Safety, Sustainability and Corporate Responsibility Committee. Copies of the Code of Conduct and the Code of Ethics for Chief Executive and Senior Financial Officers (the Codes) are also posted on our website under the “Other Governance Documents” section. Within the time period required by the SEC and the NYSE, as applicable, we will post on our website any modifications to the Codes and any waivers applicable to senior officers as defined in the applicable Code, as required by the Sarbanes-Oxley Act of 2002.
Item 1A. Risk Factors
Described below are certain risks that we believe are applicable to our business and the oil and gas industry in which we operate. There may be additional risks that are not presently material or known. You should carefully consider each of the following risks and all other information set forth in this Annual Report on Form 10-K. If any of the events described below occur, our business, financial condition, results of operations, cash flows, liquidity or access to the capital markets could be materially adversely affected.
The oil and gas industry is cyclical and crude oil, NGL and natural gas prices are volatile. A reduction in these prices could have a material adverse effect on our operations, our liquidity, and the price of our common stock.
Our ability to operate profitably, maintain adequate liquidity, grow our cash flow and pay dividends or repurchase our common stock depend upon the prices we receive for our crude oil, NGL and natural gas production. Commodity prices are cyclical and subject to global supply and demand dynamics.
A prolonged or substantial decline in commodity prices, including declines in commodity forward price curves or volatility in location-basis differentials, may have the following effects on our business:
reduction of our revenues, profit margins, operating income and cash flows;
reduction in the amount of crude oil, NGLs and natural gas that we can produce economically, leading to shut-in or early abandonment of producing wells, including low-margin US onshore wells, and increased capital requirements for abandonment operations;
certain properties in our portfolio becoming economically unviable;
impairments of proved or unproved properties or other long-lived assets;
use of cash flow to satisfy minimum obligations under throughput agreements if production is suspended;
reduction, or suspension, of our future capital investment programs, resulting in a reduced ability to develop or replace our reserves;
delay, postponement or cancellation of some of our exploration or development projects;
inability to meet exploration or continuous drilling commitments, leading to loss of leases or exploration rights;
loss of undeveloped acreage if we are unable to make scheduled delay rental payments or loss of developed acreage if our production is shut-in;
divestments of properties to generate funds to meet cash flow or liquidity requirements;
limitations on our financial condition, liquidity, including access to sources of capital, such as debt and equity, and/or ability to finance planned capital expenditures and operations;
failure of our partners to fund their share of development costs or obtain financing, which could result in delay or cancellation of future projects, thus limiting our growth and future cash flows;
inability to meet scheduled interest and/or debt payments or payments due under operating or capital leases;
a series of credit rating downgrades or other negative rating actions, which could increase our future cost of financing and may increase our requirements to post collateral as financial assurance of performance under certain other contracts, which, in turn, could have a negative impact on our liquidity and our ability to access the commercial paper market;

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changes in corporate structure that could lead to loss of key personnel and interrupt our business activities;
reduction or suspension of dividends or repurchases of our common stock;
declines in our stock price;
additional counterparty credit risk exposure on commodity hedges and joint venture receivables; and
a reduction in the carrying value of goodwill.
Our commodity price hedging arrangements in place will not fully mitigate the effects of price volatility and may also curtail benefits from future increases in commodity prices. 
Markets and prices for crude oil, NGLs and natural gas depend on factors beyond our control, factors including, among others:
global demand for crude oil, NGLs and natural gas, as impacted by economic factors that affect gross domestic product growth rates of countries around the world;
global supply for crude oil, NGLs and natural gas, as impacted by OPEC and non-OPEC countries (e.g. US, Russia, Canada);
technology advances that increase crude oil, NGL and natural gas production, thereby increasing supply;
new technologies that promote fuel efficiency or fuel efficiency regulations, such as the Corporate Average Fuel Economy (CAFE) standards, and impact demand for crude oil as a transportation fuel and reduce energy consumption;
the price and availability of alternative fuels and battery storage and the long-term impact on the crude oil market of the use of natural gas and electricity as an alternative fuel for road transportation or the use of natural gas as fuel for electricity generation impacting the demand for electricity;
developments in the global LNG market, including exports from the US;
geopolitical conditions and events, including generational leadership or regime changes, changes in government energy policies, including imposed price controls and/or product subsidies, the impact of trade embargoes or imposed tariffs, or instability/armed conflict in hydrocarbon-producing regions;
fluctuations in exchange rates of the US dollar, the currency in which the world's crude oil trade is generally denominated;
periods when production surpasses local pipeline/rail transportation and/or refining capacity, as is currently the case in the Delaware Basin, which in turn results in transportation constraints and significant discounts to our realized prices;
the level and effect of trading in commodity futures markets, including by commodity price speculators and others;
the effectiveness of worldwide conservation measures;
weather conditions;
access to government-owned and other lands for exploration and production activities; and
domestic and foreign governmental regulations and taxes.
Sector cost inflation could adversely affect our ability to execute our exploration and development plans on a timely basis and within our budget.
Our industry is cyclical and third-party oilfield equipment materials and service costs are also subject to supply and demand dynamics. During periods of decreasing levels of industry exploration and production, the demand for, and cost of, drilling rigs and oilfield services decreases. Conversely, during periods of increasing levels of industry activity, the demand for, and cost of, drilling rigs and oilfield services increases. As a result, drilling rigs and oilfield services may not be available at rates that provide a satisfactory return on our investment.
As commodity prices have strengthened, the demand for oilfield services and infrastructure, particularly in US onshore basins, has risen, leading to cost inflation for the drilling, completion and operating of wells, and for the construction and/or access to necessary oil and gas infrastructure, including access to gathering facilities, transportation and/or takeaway pipelines driven by growing production volumes. Transportation bottlenecks or infrastructure limitations caused by the increased utilization may lead to competitive pricing pressures in certain basins. As a result, there is pressure on operating margins and capital efficiency in US onshore basins, including those in which we operate. 
If this trend continues, and if commodity prices increase, we expect industry exploration and production activities to continue to increase, resulting in even higher demand for oilfield equipment services, which could result in significant sector price inflation. In addition, in basins of relatively higher activity, scarcity of competent service personnel may impact our ability to execute our exploration and development plans in a timely and profitable manner.
Concentration of capital in, and production and cash flows from, certain operations may increase our exposure to risks enumerated herein.
A significant portion of our production and revenues is highly concentrated and is generated from a limited number of conventional deepwater wells. These wells, located offshore Israel and offshore Equatorial Guinea, contributed approximately 20% of our 2018 total crude oil, NGL and natural gas revenues and 26% of our 2018 total consolidated sales volumes. In

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addition, we have a major concentration of reserves offshore Israel, with approximately 43% of our year-end 2018 proved reserves attributable to this area.
Although we carry contingent business interruption insurance for these producing assets, as well as other insurance, the insurance is insufficient to cover all potential risks.
We also have significant concentrations of capital and production in unconventional basins including the DJ Basin, Delaware Basin and Eagle Ford Shale, and we expect to invest approximately 70% of our total capital investment program to development activities in these areas in 2019. Restrictions in land access or permitting, rapid changes in drilling and completion technology, significant increases in drilling and completion costs, lack of availability of downstream services, including access to gathering facilities, transportation and/or takeaway pipelines, lack of reliable power or electricity infrastructure, changes in regulations and other risks impacting these areas, as enumerated in certain risk factors described herein, can have immediate, significant negative impacts on our production, cash flows, profitability and financial position.
We face various risks associated with the trend toward increased anti-oil and gas development activity.
In recent years, we have seen significant growth in opposition to oil and gas development both in the US and globally. 
Companies in our industry can be the target of opposition to hydrocarbon development from stakeholder groups, including national, state and local governments, regulatory agencies, non-government organizations and public citizens. This opposition is focused on attempting to limit or stop hydrocarbon development in certain areas. Examples of such opposition include: efforts to reduce access to public and private lands; delaying or canceling permits for drilling or pipeline construction; limiting or banning industry techniques such as hydraulic fracturing, and/or adding restrictions on the use of water and associated disposal; imposition of set-backs on oil and gas sites; delaying or denying air-quality permits; advocating for increased regulations, punitive taxation, or citizen ballot initiatives or moratoriums on industry activity; and the use of social media channels to cause reputational harm.
We have experienced these efforts in Colorado, recently and in the past, and it is likely they will continue into the future. For example, the State of Colorado General Assembly is currently developing a framework for future oil and gas development in the State. This initiative, together with increased pressure to allow local governments to control oil and gas operations within their borders, could result in new regulations that limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration or development in areas where we operate. We cannot predict the outcome of these initiatives or their impact on our operations.
Recent efforts by the US Administration to modify federal oil and gas related regulations could intensify the risk of anti-development efforts from grass roots opposition.
Our need to incur costs associated with responding to these anti-development efforts, including legal challenges, or complying with any new legal or regulatory requirements resulting from these efforts, could have a material adverse effect on our business, financial condition and results of operations. 
Discoveries or acquisitions of reserves are needed to avoid a material decline in reserves and production.
The production rates from oil and gas properties generally decline as reserves are depleted, while related per unit production costs generally increase due to decreasing reservoir pressures and other factors. Therefore, our estimated proved reserves and future crude oil, NGL and natural gas production will decline materially as reserves are produced unless we conduct successful exploration and development activities, such as identifying additional producing zones in existing fields, utilizing secondary or tertiary recovery techniques or gaining access to properties containing future proved reserves. Consequently, our future crude oil, NGL and natural gas production and related per unit production costs are highly dependent upon our level of success in finding or acquiring additional reserves.
The marketability of our production is dependent upon access to gathering, transportation and processing facilities, which we may not own or control.
The marketability of our production from our US onshore areas depends in part upon the availability, proximity and capacity of gathering systems, transportation pipelines, rail service, and processing facilities. We deliver crude oil, NGLs and natural gas produced from these areas through midstream infrastructure, the majority of which we do not own and may not control.
We currently rely on state-owned pipeline and transportation systems to deliver our natural gas production from offshore Israel to customers and end users in the region. In addition, with the execution of multiple agreements to supply natural gas to customers in Egypt, we have entered into an agreement to acquire an equity interest in a company that owns the EMG Pipeline, which will connect the Israel pipeline network to Egyptian customers. Initial gas delivery through the EMG Pipeline is expected to occur in 2019 and is pending certain conditions precedent. Offshore Equatorial Guinea, our natural gas production is delivered to onshore processing and storage facilities operated by our partner, and the resulting products, as well as our crude oil production from Aseng and Alen, are lifted to tankers owned by third-parties.

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Third-party systems and facilities may not be available to us in the future at a price that is acceptable to us. In addition, the lack of availability of, or capacity on, third-party systems and facilities, including those owned by Noble Midstream Partners, could reduce the price offered for our production or result in the shut-in of producing wells or the delay or discontinuance of development plans for properties. Further, the inability of third-party processors, over whom we have no control, to meet anticipated facility expansion deadlines, or to delay or even cancel projects, in areas where our production is growing, such as in the DJ Basin, could result in curtailment of our production growth and/or shut-in of production. Even where we have some contractual control over the transportation of our production through firm transportation arrangements, third-party systems and facilities may be temporarily unavailable due to market conditions or mechanical reliability or other reasons, including adverse weather conditions or geopolitical instability.
Any significant change in market factors or other conditions affecting these infrastructure systems and facilities, as well as any delays in constructing new infrastructure systems and facilities, could delay or curtail production, thereby harming our business and, in turn, our results of operations, cash flows, and financial condition.
Our international operations may be adversely affected by economic or geopolitical developments or by violent acts such as civil disturbances, terrorist acts, regime changes, cross-border violence, war, piracy, or other conflicts.
We have significant international operations in Israel and Equatorial Guinea. We also conduct exploration activities in other international areas. Notwithstanding economic stability clauses, our operations may be adversely affected by economic or political developments, including the following:
renegotiation, modification or nullification of existing contracts, which may occur pursuant to future regulations enacted as a result of changes in Israel's antitrust, export and natural gas development policies, or the hydrocarbons law enacted in 2006 by the government of Equatorial Guinea, which can increase the amount of revenues that the host government receives from production (government take) or otherwise decrease project profitability;
loss of revenue, property and equipment as a result of actions taken by host nations, such as expropriation or nationalization of assets or termination of contracts;
changes in drilling or safety regulations;
laws and policies of the US and foreign jurisdictions affecting trade, foreign investment, taxation and business conduct;
potential for Israel natural gas production and regional exports to be interrupted by political conditions and events;
difficulties enforcing our rights against a governmental agency because of the doctrine of sovereign immunity and foreign sovereignty over international operations;
US and international monetary policies impacting foreign exchange or repatriation restrictions in countries in which we conduct business; and
other hazards arising out of foreign governmental sovereignty over areas in which we conduct operations.
Such economic and political developments could have a negative impact on our results of operations and cash flows and reduce the fair values of our properties, resulting in impairment charges.
In addition, our international operations are located in, or in close proximity to, regions that continue to experience varying degrees of political instability, public protests, territorial or boundary disputes, and terrorist attacks. Terrorist attacks and the threat of terrorist attacks, whether domestic or foreign, as well as military or other actions taken in response to these acts, could cause instability in the global financial and energy markets. Continued or escalated civil and political unrest and acts of terrorism in the regions in which we operate could result in curtailment of our operations. In the event that such regions experience civil or political unrest or acts of terrorism, especially in areas where such unrest leads to regime change, our operations there could be materially impaired.
We monitor the economic and political environments of the countries in which we operate. However, we are unable to predict the occurrence of disturbances such as those noted above. In addition, we have limited ability to mitigate their impact.
Civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have the following results, among others:    
increased volatility in global crude oil, NGL and natural gas prices, which could negatively impact the global economy, resulting in slower economic growth rates, which could reduce demand for our products;
negative impact on the global crude oil supply if infrastructure or transportation are disrupted, leading to further commodity price volatility;
difficulty in attracting and retaining qualified personnel to work in areas with potential for conflict;
inability of our personnel, third-party providers or supplies to enter or exit the countries where we conduct operations;
disruption of our operations due to evacuation of personnel;
inability to deliver our production due to disruption or closing of transportation routes;
reduced ability to export our production due to efforts of countries to conserve domestic resources;

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damage to or destruction of our wells, production facilities, receiving terminals or other operating assets;
damage to or destruction of property belonging to our purchasers, leading to interruption of commodity deliveries, claims of force majeure, and/or termination of sales contracts, resulting in a reduction in our revenues;
lack of availability of drilling rigs, oilfield equipment or services if third-party providers decide to exit the region;
shutdown of a financial system, communications network, or power grid causing a disruption to our business activities; and
capital market reassessment of risk and reduction of available capital making it more difficult for us and our partners to obtain financing for potential development projects.
Loss of property and/or interruption of our business plans resulting from civil disturbances, terrorist acts, regime changes, war, or conflicts, or the threats thereof, could have a significant negative impact on our earnings and cash flow. In addition, we may not have enough insurance to cover any loss of property or other claims resulting from these risks.
Our Eastern Mediterranean discoveries bear certain technical, geopolitical, regulatory, and financial challenges that could adversely impact our ability to monetize these natural gas assets.
Due to the scale of our Leviathan (Israel) and Aphrodite (Cyprus) discoveries, realization of their full economic value depends on our ability to execute successful phased development scenarios, the failure or delay of which could reduce our future growth and have negative effects on our future operating results. Offshore projects of this magnitude entail significant technical complexities, including subsea tiebacks to a FPSO or production platform, pressure maintenance systems, gas re-injection systems, onshore receiving terminals, or other specialized infrastructure. In addition, we depend on third-party technology and service providers and other supply chain participants for these complex projects. Delays and differences between estimated and actual timing of critical events related to these projects could have a material adverse effect on our results of operations.
We have entered into and are currently negotiating various long-term GSPAs for our Eastern Mediterranean natural gas assets. Some of these agreements require the export of natural gas from either Israel or Cyprus to other countries in the region, such as Egypt and Jordan. These agreements are subject to a variety of risks, including geopolitical, regulatory, financial and other uncertainties. War, political violence, civil unrest or lack of intergovernmental cooperation could affect both our and our counterparties’ abilities to cooperate and to perform under these agreements, and could potentially lead to a breach or termination of such agreements. In addition, economic conditions or financial duress of our counterparties could jeopardize their ability to fulfill their payment obligations under these contracts. Furthermore, if material disruptions occur, including events or circumstances constituting force majeure under contract provisions, such that they inhibit us or our counterparties from performing under these GSPAs, or our counterparties are unable to pay us for a sustained period of time, we could incur a significant decline in revenues. While the State of Israel continues to maintain its ability to generate electricity via coal-fired power plants, as they transition from coal-fired power plants to natural gas-fired power plants, it is becoming more dependent on us and our partners for its source of natural gas supply. Any material disruption in our ability to deliver natural gas to the State of Israel could have a material impact on our expected profitability, financial performance and reputation.
A cyber incident could result in information theft, data corruption, operational disruption and/or financial loss.
We are increasingly dependent on digital technology, including information systems and related infrastructure, as well as cloud applications and services, to process and record financial and operating data, communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves as well as other activities related to our business. Our business partners, including suppliers, service providers, purchasers of our production, and financial institutions, are also dependent on digital technology. The technologies needed to conduct oil and gas exploration and development activities in deepwater, ultra-deepwater and shale, as well as technologies supporting midstream operations and global competition for oil and gas resources make certain information the target of theft or misappropriation.
As dependence on digital technologies has increased, cyber incidents, including deliberate attacks or unintentional events, have also increased. A cyber attack could include gaining unauthorized access to digital systems for purposes of misappropriating assets or sensitive information, corrupting data, or causing operational disruption, or result in denial-of-service on websites. Supervisory control and data acquisition (SCADA) based systems are potentially vulnerable to targeted cyber attacks due to their critical role in operations.
Our technologies, systems, networks, and those of our business partners may become the target of cyber attacks or information security breaches that could result in the unauthorized release, gathering, monitoring, misuse, loss or destruction of proprietary and other information, or other disruption of our business operations. In addition, certain cyber incidents, such as surveillance, may remain undetected for an extended period.
A cyber incident involving our information systems and related infrastructure, or that of our business partners, could disrupt our business plans and negatively impact our operations in the following ways, among others:
unauthorized access to seismic data, reserves information or other sensitive or proprietary information could have a negative impact on our ability to compete for oil and gas resources;

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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 disruption of production infrastructure could result in loss of production, or accidental discharge;
a cyber attack on a supplier or service provider could result in supply chain disruptions which could delay or halt a development project, effectively delaying the start of cash flows from the project;
a cyber attack on a third-party gathering or pipeline service provider could prevent us from 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 deliberate corruption of our financial or operational data, or data theft, could result in events of non-compliance which could lead to regulatory fines or penalties; and
business interruptions, including use of social engineering schemes and/or ransomware, could result in expensive remediation efforts, distraction of management, damage to our reputation, or a negative impact on the price of our common stock.
Our implementation of various controls and processes to monitor and mitigate security threats and to increase security for our information, facilities and infrastructure is costly and labor intensive. Moreover, there can be no assurance that such measures will be sufficient to prevent security breaches from occurring. 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.
We are subject to increasing governmental regulations and environmental requirements that may restrict our access to land and/or cause us to incur substantial incremental costs.
Our industry is subject to complex laws and regulations adopted or promulgated by international, federal, state and local authorities relating to the exploration for, and the development, production and marketing of, crude oil, NGLs and natural gas. As the various government and/or regulatory bodies issue or rescind various regulations, our operations are subject to significant volatility in response to the issuance, interpretation and application of these regulations.
Examples of factors which reduce our land access, including loss of access to land for which we own mineral rights, reduced ability to obtain new leases, or loss of rights granted under surface use agreements, rights-of-way, surface leases or other easement rights, include, among others:
new municipal, state or federal land use regulations, which may restrict drilling locations or certain activities such as hydraulic fracturing;
local and municipal government control of land or zoning requirements, which can conflict with state law and deprive land owners of property development rights;
landowner, community and/or governmental opposition to infrastructure development;
regulation of federal and Indian land by the BLM; and
the presence of threatened or endangered species or of their habitat.
In the state of Colorado, for example, since 2014 we have encountered citizen driven ballot initiatives and other legislative proposals to regulate, limit or ban hydraulic fracturing or other facets of crude oil and natural gas exploration, development or operations. See Items 1. and 2. Business and Properties – Regulations – Colorado.
Changes in price controls, taxes and environmental laws relating to our industry also have the ability to substantially affect crude oil, NGL and natural gas production, operations and economics. Environmental laws, in particular, can change frequently, often become stricter and at times may force us to incur additional costs as changes are implemented.
Under certain environmental laws that impose strict as well as joint and several liability, we may be required to remediate contaminated properties currently or formerly operated by us or facilities of third parties that received waste generated by our operations regardless of whether such contamination resulted from the conduct of others or from consequences of our own actions that were in compliance with all applicable laws at the time those actions were taken. In addition, claims for damages to persons or property, including natural resources, may result from the environmental, health and safety impacts of our operations. Additionally, the accidental and/or unpermitted discharge of natural gas, crude oil, or other pollutants into the air, soil or water may give rise to liabilities on our part to government agencies and/or third parties, and may require us to incur

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Noncompliance with existing or future legislation or regulations could potentially result in an increased risk of civil or criminal fines or sanctions. Fines or sanctions associated with a well incident or spill could well exceed the actual cost of containment and cleanup. In addition, we cannot always predict with certainty how agencies or courts will interpret existing laws and regulations or the effect these interpretations may have on our business or financial condition.
Restricted land access, further expansion of environmental, safety and performance regulations or an increase in liability for drilling or production activities, including punitive fines, may have one or more of the following impacts on our business:
reduce our proved reserves;
reduce our ability to explore for new proved reserves;
increase exploratory and development well drilling costs, operating or other costs;
delay, or preclude, project development resulting in longer development cycle times;
disrupt or prohibit our ability to construct or operate midstream assets;
divert our cash flows from capital investments in order to maintain liquidity;
increase or remove liability caps for claims of damages from oil spills;
increase our share of civil or criminal fines or sanctions for actual or alleged violations if a well incident were to occur; and
limit our ability to obtain additional insurance coverage, at a level that balances the cost of insurance and our desired rates of return, to protect against any increase in liability.
Any of the above operating or financial factors could have a material adverse effect on our business, financial condition, results of operations, and cash flows and may result in a reduction of the fair value of our properties or reduce our financial flexibility. Because we strive to achieve certain levels of return on our projects, an increase in our financial responsibility could result in certain of our planned projects becoming uneconomic. See Items 1. and 2. Business and Properties – Regulations.
Our operations may be adversely affected by changes in the fiscal regimes and related government policies, tax laws and regulations in the US and other countries in which we operate.
Fiscal regimes impact oil and gas companies through laws and regulations governing resource access, along with government participation in oil and gas projects, royalties and taxes. We operate in the US and other countries whose fiscal regimes may change over time. Changes in fiscal regimes result in an increase or decrease in the amount of government financial take from developments, and a corresponding decrease or increase in the revenues of an oil and gas company operating in that particular country. For example, a significant portion of our production comes from Israel and Equatorial Guinea; therefore, changes in or uncertainties related to the fiscal regimes or energy policies of these countries could delay or reduce the profitability of our development projects, and/or render future exploration and development projects uneconomic.
The elimination of tax deductions, as well as any other changes to or the imposition of new federal, state, local or non-US taxes (including the imposition of, or increases in production, severance or similar taxes) could also have a significant impact on our operations and financial performance. For example, on December 22, 2017, the US Congress enacted tax reform legislation known as the Tax Cuts and Jobs Act (Tax Reform Legislation). The Tax Reform Legislation is complex and far-reaching, making sweeping modifications to the Internal Revenue Code including a lower corporate tax rate, changes to credits and deductions, and a move to a territorial system for corporations that have overseas earnings.
Periodically, other legislative amendments may be proposed that, if enacted into law, would make additional significant changes to US federal and state income tax laws, such as (i) the elimination of the immediate deduction for intangible drilling and development costs and (ii) an extension of the amortization period for certain geological and geophysical expenditures. No accurate prediction can be made as to whether any such legislative changes will be proposed or enacted in the future, or the timing of any such action. Further, we cannot predict how government agencies or courts will interpret existing regulations and tax laws, including Tax Reform Legislation, or the effect such interpretations could have on our business.
Changes in fiscal regimes, including changes in tax laws and regulations, have long-term impacts on our business strategy, and fiscal uncertainty makes it difficult to formulate and execute capital investment programs. The implementation of new, or the modification of existing, laws or regulations increasing the tax costs on our business could disrupt our business plans and negatively impact our operations and our stock price in the following ways, among others:
restrict resource access or investment in lease holdings;
limit or cancel exploration and/or development activities, which could have a long-term negative impact on the quantities of proved reserves we record and inhibit future production growth;
negatively impact our and/or our partners' ability to obtain financing;
reduce the profitability of our projects, resulting in decreases in net income and cash flows with the potential to make future investments uneconomical;

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result in currently producing projects becoming uneconomic, to the extent fiscal changes are retroactive, thereby reducing the amount of proved reserves we record and cash flows we receive, and possibly resulting in asset impairment charges;
require that valuation allowances be established against deferred tax assets, with offsetting increases in income tax expense, resulting in decreases in net income and cash flow; and/or
restrict our ability to compete with imported volumes of crude oil or natural gas.
A change in international and/or US federal and state climate policy could have a significant impact on our operations and profitability.
Domestic and international responses to climate and related energy issues are matters of public policy consideration. We are currently in a period of increasing uncertainty as to these matters and, at this time, it is difficult to anticipate how the current US Administration, or other entities, may act on existing or new laws and regulations. As compared with certain large multi-national, integrated energy companies, we do not conduct fundamental research regarding the scientific inquiry of climate change. However, we will continue to closely monitor all relevant developments in this regard. Changes in international, federal or state laws and regulations regarding climate policy could have a significant negative impact on our ability to explore for and develop crude oil and natural gas resources or reduce demand for our products.
In recent years, international, federal, state and local governments have taken steps to reduce emissions of greenhouse gases. The EPA has finalized a series of greenhouse gas monitoring, reporting and emissions control rules for the oil and natural gas industry, and the US Congress has, from time to time, considered adopting legislation to reduce emissions. Almost one-half of states in the US have taken measures to reduce emissions of greenhouse gases primarily through the development of greenhouse gas emission inventories and/or regional greenhouse gas cap-and-trade programs. For a description of existing and proposed greenhouse gas rules and regulations, see Items 1. and 2. Business and Properties – Regulations.
Furthermore, claims have been made against certain energy companies alleging that greenhouse gas emissions from oil and natural gas operations constitute a public nuisance under federal and/or state common law. As a result, private individuals or other entities may make claims against us for alleged personal injury, property damage, or other potential liabilities. While our business is not a party to any such litigation, we could be named in actions making similar allegations. An unfavorable ruling in any such case could impact our operations and could have an adverse impact on our financial condition.
Additionally, there has been public discussion that climate change may be associated with extreme weather conditions such as more intense hurricanes, thunderstorms, tornadoes, drought and snow or ice storms, as well as rising sea levels. Extreme weather conditions can interfere with our production and increase our costs, and damage resulting from extreme weather may not be fully insured.
Our operations require us to comply with a number of US and international laws and regulations, violations of which could result in substantial fines or sanctions and/or impair our ability to do business.
Our operations require us to comply with complex and frequently-changing US and international laws and regulations, such as those involving anti-corruption, competition and antitrust, anti-boycott, anti-money laundering, import-export control, marketing, environmental and/or taxation.
For example, the US Foreign Corrupt Practices Act (FCPA) and similar laws and regulations generally prohibit improper payments to foreign officials for the purpose of obtaining or keeping business. We conduct some of our operations in developing countries that have relatively underdeveloped legal and regulatory systems compared to more developed countries. These countries generally are perceived as presenting an increased risk of corruption. Additionally, certain of our operations involve the use of agents and other intermediaries whose conduct and actions could be imputed to us by anti-corruption enforcement authorities. Violations of the FCPA or other anti-corruption laws could subject us to substantial fines or sanctions and impair our ability to do business.
The import/export of equipment and supplies necessary for oil and gas exploration and development activities, as well as the export of crude oil, liquids and natural gas production are regulated by the import/export laws of the US and other countries in which we operate. In the US, certain items required for oil and gas development activities may be considered “dual-use”, having both commercial and military applications and, therefore, may be subject to specific import or export restrictions. In addition, the US government imposes economic and trade sanctions against certain foreign countries and regimes. The sanctions are based on US foreign policy and national security goals and may change over time.
As a developer, owner and operator of crude oil and natural gas properties, we are subject to various laws and regulations relating to the discharge of materials into, and the protection of, the environment. 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, the suspension or revocation of necessary permits, licenses and authorizations, the requirement that additional pollution controls be installed and, in some instances, issuance of orders or injunctions limiting or requiring discontinuation of certain operations. See We are subject to increasing governmental regulations and environmental

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requirements that may restrict our access to land and/or cause us to incur substantial incremental costs, above, and Item 8. Financial Statements and Supplementary Data – Note 11. Commitments and Contingencies.
Federal, state and local hydraulic fracturing and water disposal legislation and regulation could increase our costs or restrict our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities.
While hydraulic fracturing has been utilized in oil and gas development for decades, certain parties have called for further study of the technique's alleged environmental and health effects, for additional regulation of the technique and, in some cases, for a moratorium or ban on the use of hydraulic fracturing. Because of elevated public sensitivity around the topic, federal, state and local governments are continually conducting studies, evaluating their regulatory programs and considering additional requirements on and regulation of hydraulic fracturing practices. At the national level, proposals have been introduced from time to time in the US Congress that, if implemented, would subject hydraulic fracturing to further regulation, thereby limiting its use or increasing its cost.
Federal agencies addressing hydraulic fracturing under existing authorities include the EPA and the BLM, under the US Department of the Interior. In 2017, an executive order was signed directing the EPA and the BLM to review their rules and, if appropriate, initiate rulemaking to rescind or revise them consistent with the stated policy of promoting clean and safe development of the nation’s energy resources, while at the same time avoiding regulatory burdens that unnecessarily encumber energy production. Accordingly, the EPA and the BLM have taken actions to delay or rescind certain requirements related to hydraulic fracturing activities. See Items 1. and 2. Business and Properties – Hydraulic Fracturing.
Each of the states, as well as certain localities, where we operate have adopted or may adopt regulations on drilling activities in general or hydraulic fracturing in particular that could restrict or prohibit hydraulic fracturing in certain circumstances, impose more stringent operating standards and/or require the disclosure of the composition of hydraulic fracturing fluids. For example, a number of local communities in Colorado have attempted to increase regulatory requirements on crude oil and natural gas development. In addition, some state regulatory agencies have modified their regulations to account for potential induced seismicity with regard to the operation of injection wells used for waste disposal.
Furthermore, there are certain governmental reviews either underway or being proposed that focus on environmental aspects of hydraulic fracturing practices. On December 13, 2016, the EPA released a study examining the potential for hydraulic fracturing activities to impact drinking water resources, finding that, under some circumstances, the use of water in hydraulic fracturing activities can impact drinking water resources. Also, on February 6, 2015, the EPA released a report with findings and recommendations related to public concern about induced seismic activity from disposal wells. The report recommends strategies for managing and minimizing the potential for significant injection-induced seismic events. Other governmental agencies, including the US Department of Energy, the US Geological Survey, and the US Government Accountability Office, have evaluated or are evaluating various other aspects of hydraulic fracturing. These ongoing or proposed studies could spur initiatives to further regulate hydraulic fracturing, and could ultimately make it more difficult or costly for us to perform fracturing and increase our costs of compliance and doing business.
We are dependent on the use of hydraulic fracturing practices to produce commercial quantities of crude oil and natural gas, particularly from wells in our US onshore basins. Additional federal, state or local restrictions on hydraulic fracturing, water disposal or other drilling activities that may be imposed in areas where we conduct business, such as US onshore, could significantly increase our operating, capital and compliance costs, as well as delay or halt our ability to develop crude oil, NGL and natural gas reserves. See Items 1. and 2. Business and Properties – Regulations and – Hydraulic Fracturing.
Exploration, development and production activities carry inherent risk. These activities, as well as natural disasters or adverse weather conditions, could result in liability exposure or the loss of production and revenues.
Our operations are subject to hazards and risks inherent in the drilling, production and transportation of crude oil, NGLs and natural gas, including:
pipeline ruptures and spills;
fires, explosions, blowouts and well cratering;
equipment malfunctions and/or mechanical failure on high-volume, high-impact wells;
malfunctions of, or damage to, gathering, processing, compression and transportation facilities and equipment and other facilities and equipment utilized in support of our crude oil, NGL and natural gas operations;
leaks or spills occurring during the transfer of hydrocarbons from an FPSO to an oil tanker;
loss of product occurring as a result of transfer to a truck or rail car or train derailments;
leakage or loss of access to hydrocarbons resulting from formations with abnormal pressures and basin subsidence;
release of pollutants; and
spills, leaks or discharges of fluids used in or produced in the course of operations, especially those that reach surface water or groundwater.

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Some of these risks or hazards could materially and adversely affect our revenues and expenses by reducing or shutting in production from wells, causing the loss of equipment or otherwise negatively impacting the projected economic performance of our projects. In addition, our ability to deliver product pursuant to long-term supply contracts could be negatively impacted, resulting in additional financial exposure in the event we cannot fully deliver the contract quantities.
Any of these risks or hazards can result in injuries and/or deaths of employees, supplier personnel or other individuals, loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, regulatory investigations and administrative, civil and criminal penalties or restricted access to our properties.
In addition, our operations and financial results could be significantly impacted by adverse weather conditions and natural disasters in the areas we operate including:
hurricanes, tropical storms, windstorms, or “superstorms,” which could affect our operations in areas such as Texas;
winter storms and snow, which could affect our operations in the DJ Basin;
extremely high temperatures, which could affect our midstream or third-party gathering and processing facilities in the DJ Basin and Texas;
severe droughts, which could result in new restrictions on water usage in the DJ Basin and Texas;
harsh weather and rough seas offshore international locations, which could limit exploration activities; and
other natural disasters.
Any of these can result in loss of hydrocarbons, environmental pollution and other damage to our properties or the properties of others, or restricted access to our properties.
Development drilling may not result in commercially productive quantities of crude oil and natural gas reserves from unconventional or conventional resources.
We depend on development projects to provide sustained cash flows after investment and attractive financial returns. However, development drilling is not always successful and the profitability of development projects may change over time.
In new development areas, including certain shale formations, available data may not allow us to completely know the extent of the reservoir or the best locations for drilling development wells. Therefore, a development well we drill, or in which we participate, may be a dry hole, may result in noncommercial quantities of hydrocarbons or may be less productive than our initial estimates.
We expect to invest significant amounts of capital to continue development of our US onshore unconventional resources and to progress the development of the Leviathan field project. In unconventional basins, development is highly dependent on costs of equipment and services, the use of technologies to drive capital and cost efficiencies in drilling and completion, and the availability of and access to midstream infrastructure. Even if development drilling is successful and we find commercial quantities of reserves, we may encounter difficulties or delays in completing development wells. For example, frontier areas or less developed onshore areas may not have adequate infrastructure for gathering, transportation or processing, and production may be delayed until such infrastructure is constructed.
Exploratory drilling subjects us to risks and may not result in the discovery of commercially productive reservoirs.
Exploratory drilling requires significant capital investment and does not always result in commercial quantities of hydrocarbons or new development projects. In addition, exploratory drilling activities may be curtailed, delayed or canceled, or development plans may change, resulting in significant exploration expense, as a result of a variety of factors, including unexpected drilling conditions and pressure or other irregularities in formations. Furthermore, remote locations may make it more difficult and time-consuming to transport personnel, equipment and supplies, and we may face more difficult environments, such as oil sands, deepwater, or ultra-deepwater, in our efforts to seek new reserves, and may need to develop or invest in new technologies. These operating environments, and potential for harsh weather, increase cost as well as drilling risk.
Exploratory dry holes can occur because seismic data and other technologies we use to determine potential exploratory drilling locations do not allow us to know conclusively prior to drilling a well that crude oil or natural gas is present or may be produced economically. In addition, a well may be successful in locating hydrocarbons, but we and our partners may decide not to develop the prospect due to other considerations.
In addition, for certain capital-intensive offshore projects, it may take several years to evaluate the future potential of an exploratory well and make a determination of its economic viability, resulting in delays in cash flows from production start-up and a lower return on our investment.
We hold working interests in certain areas, including offshore areas of Cyprus, Cameroon, Gabon and Newfoundland (Canada) where there is minimal or no crude oil, NGL or natural gas production, and in certain cases, limited infrastructure. If commercial quantities of hydrocarbons are discovered, areas with minimal or no current production must begin to address topics such as sector regulation and distribution of government proceeds from hydrocarbon sales, the results of which could

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have a negative impact on our business. We may not be able to compensate for or fully mitigate these risks. See Item 8. Financial Statements and Supplementary Data – Note 7. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs.
Failure to adequately fund continued capital expenditures could adversely affect our properties.
Our exploration, development, and acquisition activities require capital expenditures to achieve production and cash flows. In particular, major offshore projects have a multi-year long development cycle time, which means that development spending occurs for several years before the project begins producing hydrocarbons and generating cash flows. As examples, assets and infrastructure for export of natural gas from Leviathan require a multi-billion dollar investment prior to production startup. Furthermore, while our DJ Basin assets are primarily held by production, other assets, such as our Eagle Ford Shale and Delaware Basin properties, are held primarily through continuous development obligations. Therefore, we are contractually obligated to fund a level of development activity in these areas, the amount of which could be substantial, or exercise options with land owners to extend leases. Failure to meet continuous development obligations or to exercise lease extensions may result in loss of leases.
Historically, we have funded our capital expenditures through a combination of cash flows from operations, our Revolving Credit Facility (defined below), debt and equity issuances, and occasional sales of assets. Future cash flows from operations are subject to a number of variables, as enumerated herein. If commodity prices decline for an extended period of time, we will evaluate our level of capital spending and likely reduce our investment program. As a result, we will have less ability to replace our reserves through drilling operations and may elect to forfeit our ownership interests or rights to participate in some properties, resulting in lower production over time as compared with prior years. See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Operating Outlook – 2019 Capital Investment Program.
Our Midstream reportable segment derives a substantial portion of its revenue from unaffiliated, third party customers. If any of these customers changes its business strategy, alters current drilling and development plans on dedicated acreage, or otherwise significantly reduces the volumes of crude oil, natural gas, produced water or fresh water with respect to which we perform midstream services, our Midstream revenues would decline and have negative impacts on our business, financial condition, results of operations, and cash flows.
We have numerous commercial agreements to provide midstream services and crude oil sales for unaffiliated third-party customers, some of whom are non-investment grade. Accordingly, because we derive a substantial portion of our midstream revenue from these commercial agreements, we are subject to the operational and business risks of these customers, the most significant of which include the following:
a reduction in or slowing of customer drilling and development plans on our dedicated acreage, which would directly and adversely impact demand for our midstream services;
the volatility of crude oil, natural gas and NGL prices, which could have a negative effect on our customers’ drilling and development plans on our dedicated acreage or ability to finance their operations and drilling and completion costs on our dedicated acreage;
the availability of capital on an economic basis for our customers to fund their exploration and development activities;
drilling and operating risks associated with customer operations on our dedicated acreage;
downstream processing and transportation capacity constraints and interruptions, including the failure of our customers to have sufficient contracted processing or transportation capacity; and
adverse effects of increased or changed governmental and environmental regulation or enforcement of existing regulation.
Further, we have no control over our customers’ business decisions and operations, and our customers are under no obligation to adopt a business strategy that is favorable to us. Thus, we are subject to the risk of cancellation of planned development, breach of commitments with respect to future dedications, and other non-payment or non-performance by our customers, including with respect to our commercial agreements, which do not contain minimum volume commitments.
Our ability to produce crude oil, NGLs and natural gas economically and in commercial quantities could be impaired if we are unable to acquire adequate supplies of water for our drilling operations or are unable to dispose of or recycle the water we use economically and in an environmentally safe manner.
Drilling and development activities require the use of water and results in the production of waste water. For example, the hydraulic fracturing process, which we employ to produce commercial quantities of crude oil, NGLs and natural gas from many reservoirs, requires the use and disposal of significant quantities of water. In certain regions, there may be insufficient local capacity to provide a source of water for drilling activities. In those cases, water must be obtained from other sources and transported to the drilling site, adding to the development cost. Waste water from oil and gas operations often is disposed of via underground injection. Some studies have linked earthquakes or induced seismicity in certain areas to underground injection, which is leading to increased public scrutiny of injection safety.

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The development of new environmental initiatives or regulations related to acquisition, withdrawal, storage and use of surface water or groundwater, or treatment and discharge of water waste, may limit our ability to use techniques such as hydraulic fracturing, increase our development and operating costs and cause delays, interruptions or termination of our operations, the extent of which cannot be predicted and all of which could have an adverse effect on our operations and financial condition. See Items 1. and 2. Business and Properties – Hydraulic Fracturing.
A negative shift in investor sentiment of the oil and gas industry could adversely affect our ability to raise debt and equity capital.
Certain segments of the investor community have developed negative sentiment towards investing in our industry. Recent equity returns in the sector versus other industry sectors have led to lower oil and gas representation in certain key equity market indices. In addition, some investors, including investment advisors and certain sovereign wealth, pension funds, university endowments and family foundations, have stated policies to disinvest in the oil and gas sector based on their social and environmental considerations. Certain other stakeholders have also pressured commercial and investment banks to stop financing oil and gas and related infrastructure projects.
Such developments, including environmental activism and initiatives aimed at limiting climate change and reducing air pollution, could result in downward pressure on the stock prices of oil and gas companies, including ours. This may also potentially result in a reduction of available capital funding for potential development projects, impacting our future financial results.
We face various risks associated with global populism and general political uncertainty.
Following the 2008/2009 global financial crisis, the world has experienced lower economic growth versus the levels attained in previous decades. Recent trade tensions and tariff disputes, including retaliation to such policies which have the potential to escalate into global trade wars, have also contributed to a slowing of global trade activities further compounding concerns around jobs, economic well-being and wealth distribution. Globally, certain individuals and organizations are attempting to focus the public's attention on income and wealth distribution and implement income and wealth redistribution policies.
Recent events have intensified these risks. Globally, and in the US, the growing trends toward populism and political polarization have resulted in uncertainty regarding potential changes in regulations, fiscal policy, social programs, domestic and foreign relations and international trade policies and tariffs.
Changes in relationships among the US, China and Russia, and/or among China, Russia and other countries, have potentially significant impacts on the global balance of power, as well as on global trade, with resultant impacts on both global and local economies. In addition, changes in the relationship between the US and its neighbors is currently impacting commerce and trade across the North American continent. In Europe, the populist movement has resulted in the Brexit vote and increasing populist demands coupled with rising nationalism could have a negative impact on economic policy and consequently pose a potential threat to economic growth as well as the unity of the European Union.
Trade and/or tariff disputes could result in increased costs or shortages of materials and supplies the oil and gas industry relies on to produce, process and transport its oil and gas production. Our ability to respond to these developments or comply with any resulting new legal or regulatory requirements, including those involving economic and trade sanctions, could reduce our ability to negotiate the sale of our products, increase our costs of doing business, reduce our financial flexibility and otherwise have a material adverse effect on our business, financial condition and results of our operations.
Indebtedness may limit our liquidity and financial flexibility.
At December 31, 2018, we had $6.6 billion of consolidated debt, of which $560 million relates to Noble Midstream Partners, and indebtedness represented 39% of our total book capitalization (sum of debt plus shareholders' equity).
Indebtedness affects our operations in several ways, including the following:
a portion of our cash flows from operating activities must be used to service our indebtedness and is not available for other purposes;    
we may be at a competitive disadvantage as compared to similar companies that have less debt;
a covenant contained in our Credit Agreement provides that our total debt to capitalization ratio (as defined in the Credit Agreement) may not exceed 65% at any time, which may make additional borrowings more expensive, thereby affecting our flexibility in planning for, and reacting to, changes in the economy and our industry;    
additional future financing for working capital, capital expenditures, acquisitions, general corporate or other purposes may have higher costs and more restrictive covenants; and
we may be more vulnerable to general adverse economic and industry conditions.
We may incur additional debt in order to fund our exploration, development and acquisition activities. A higher level of indebtedness increases the risk that our financial flexibility may deteriorate. Our ability to meet our debt obligations and service

36


our debt depends on future performance. General economic conditions, commodity prices, and financial, business and other factors may affect our operations and our future performance. Many of these factors are beyond our control and we may not be able to generate sufficient cash flow to pay the interest on our debt, and future working capital, borrowings and equity financing may not be available to pay or refinance such debt.
In addition, a downgrade or other negative rating action could affect our requirements to post collateral as financial assurance of performance under certain contractual arrangements, such as pipeline transportation contracts, crude oil and natural gas sales contracts, work commitments and certain abandonment obligations. A lowering of our debt credit rating may negatively affect the cost, terms, conditions and/or availability of future financing, including access to the commercial paper market, and lower ratings will increase the interest rate and fees we pay on our Revolving Credit Facility. These actions, in turn, could result in negative impacts on our business, financial condition and liquidity. See Item 8. Financial Statements and Supplementary Data – Note 9. Long-Term Debt.
We face significant competition and many of our competitors have resources in excess of our available resources.
We operate in highly competitive areas of crude oil and natural gas exploration, development, acquisition and production. We face intense competition from various types of competitors ranging from large multi-national, integrated oil and gas companies, to state-controlled national oil companies, to independent oil and gas companies, to privately backed oil and gas equity funds, to name a few.
We also face competition in a number of areas such as:
acquiring desirable producing properties or new leases for future exploration;
acquiring or increasing access to gathering, transportation and processing services and capacity;
marketing our crude oil, NGL and natural gas production;
acquiring the equipment and expertise necessary to operate and develop properties; and
attracting and retaining employees with certain skills.
Many of our competitors have financial and other resources substantially in excess of those available to us. Such companies may be able to pay more for seismic information and lease rights on crude oil and natural gas properties and exploratory prospects and to define, evaluate, bid for and purchase a greater number of properties and prospects than our financial or human resources permit. This highly competitive environment could have an adverse impact on our business. See Items 1. and 2. Business and Properties – Competition.
Estimates of crude oil, NGL and natural gas reserves are not precise.
Reservoir engineering is a subjective process of estimating underground accumulations of crude oil, NGLs and natural gas that cannot be measured in an exact manner, and there are numerous uncertainties inherent in estimating reserves quantities and their value, including factors that are beyond our control.
In accordance with the SEC's rules for oil and gas reserves reporting, our reserves estimates are based on 12-month average commodity prices; therefore, reserves quantities will change when actual prices increase or decrease. As estimated production, development and abandonment costs are based on year-end economic conditions, reserves quantities will also change when these costs increase or decrease.
Reserves estimates depend on a number of factors and assumptions that may vary considerably from actual results, including:
historical production from the area compared with production from other areas;
assumed effects of regulations by governmental agencies, including the SEC;
anticipated development cycle time;
future development costs;
future operating and abandonment costs;
impacts of cost recovery provisions in contracts with foreign governments;
severance and excise taxes; and
workover and remedial costs.
For these reasons, estimates of the economically recoverable quantities of crude oil, NGLs and natural gas attributable to any particular group of properties, classifications of those reserves based on risk of recovery, and estimates of the future net cash flows expected from them prepared by different petroleum engineers, or by the same petroleum engineers but at different times, may vary substantially. Estimation of crude oil, NGL and natural gas reserves in emerging areas or areas with limited historical production is inherently more difficult, and we may have less experience in such areas. Accordingly, reserves estimates may be subject to positive or negative revisions, and actual production, revenues and expenditures with respect to our reserves likely will vary, possibly materially, from estimates. Any such negative revisions could result in an asset impairment charge.

37


Additionally, some of our reserves estimates are calculated using volumetric analysis, which involves estimating the volume of a reservoir based on the net feet of pay of the structure and an estimation of the area covered by the structure. Reserves estimates using volumetric analysis are less reliable than estimates based on a lengthy production history.
In addition, realization or recognition of PUDs will depend on our development schedule and plans. A change in future development plans for PUDs could cause the discontinuation of the classification of these reserves as proved. See Items 1. and 2. Business and Properties – Proved Reserves Disclosures.
We operate in a litigious environment.
Some of the jurisdictions within which we operate have proven to be litigious environments. Oil and gas companies can be involved in various legal proceedings and disputes with landowners, royalty owners, or other operators over matters such as leases, title transfer, joint interest billing arrangements, revenue distribution, or production or cost sharing arrangements, in the ordinary course of business. For example, in certain states, oil and gas companies are often the target of “legacy lawsuits,” by which a landowner claims that oil and gas operations, often performed many years ago and by another operator, caused pollution or contamination of a property. Various properties we have owned over the past decades potentially expose us to “legacy lawsuit” claims. Similarly, neighboring landowners may allege that current operations cause contamination or create a nuisance.
Because we maintain a diversified portfolio of assets that includes both US and international projects, the complexity and types of legal procedures with which we may become involved may vary, and we could incur significant legal and support expenses in different jurisdictions. For example, we historically have had to address certain fiscal, antitrust and other regulatory challenges in Israel, including a current lawsuit filed by petitioners alleging we and our partners in Tamar violated antitrust laws through the monopolistic pricing of natural gas to the citizens of Israel. Legal proceedings such as this could result in substantial liability and/or negative publicity about us and adversely affect the price of our common stock. In addition, legal proceedings distract management and other personnel from their primary responsibilities. These proceedings are subject to the uncertainties inherent in any litigation. We will defend ourselves vigorously in all such matters. However, if we are not able to successfully defend ourselves, there could be a delay or even a halt in our exploration, development or production activities or other business plans, resulting in a reduction in reserves, loss of production and reduced cash flows.
One of our subsidiaries acts as the general partner of a publicly traded master limited partnership, Noble Midstream Partners, which may involve a potential legal liability.
One of our subsidiaries acts as the general partner of Noble Midstream Partners, a publicly traded master limited partnership. Our control of the general partner of Noble Midstream Partners may increase the possibility that we could be subject to claims of breach of fiduciary duties, including claims of conflicts of interest, related to Noble Midstream Partners. Any liability resulting from such claims could have a material adverse effect on our future business, financial condition, results of operations and cash flows.
We may be subject to risks in connection with acquisition and divestiture activities.
As part of our business strategy, we have made, and will likely continue to make, acquisitions of oil and gas properties and/or entities that own them. If we are unable to make attractive acquisitions, our future growth could be limited. Moreover, even if we do make acquisitions, they may not result in an increase in our cash flows from operations or otherwise result in the benefits anticipated due to various risks, including, but not limited to:
incorrect estimates or assumptions about reserves, exploration potential or potential drilling locations;
incorrect assumptions regarding future revenues, including future commodity prices and differentials, or regarding future development and operating costs;
incorrect assumptions regarding potential synergies and the overall costs of equity or debt;
difficulties in integrating the operations, technologies, products and personnel of the acquired assets or business; and
unknown and unforeseen liabilities or other issues related to any acquisition for which contractual protections prove inadequate, including environmental liabilities and title defects.
Mergers of businesses often require the approval of certain government or regulatory agencies and such approval could contain terms, conditions, or restrictions that would be detrimental to our business after a merger. US antitrust laws require waiting periods and even after completion of a merger, governmental authorities could seek to block or challenge a merger as they deem necessary or desirable in the public interest. We have merged with or acquired other companies in the past. Prevention of a merger by antitrust laws could impair our ability to do business. Furthermore, mergers and acquisitions expose us to potential lawsuits or other obligations not yet anticipated at time of merger or acquisition. Such liabilities and obligations could hinder our ability to fully benefit from the acquired business or assets and negatively impact our financial performance.
The acquisition of a property or business requires management to make complex judgments and assessments, and the accuracy of the assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties

38


that we believe to be consistent with industry practices. Our review will not reveal all existing or potential problems, nor will it permit us to become sufficiently familiar with the properties to fully assess their deficiencies and capabilities.
We also maintain an ongoing portfolio management program to ensure our company is well-positioned with assets that offer growth at financially attractive investment options. Therefore, we may periodically divest certain material assets. We strive to obtain the most attractive prices for our assets; however, various factors can materially affect our ability to dispose of assets on terms acceptable to us. Such factors may include:
current commodity prices;
laws and regulations impacting oil and gas operations in the areas where the assets are located;
willingness of the purchaser to assume certain liabilities such as asset retirement obligations;
our willingness to indemnify buyers for certain matters; and
delays in closing.
Inability to achieve a desired price for the assets, or underestimation of amounts of retained liabilities or indemnification obligations, can result in a reduction of cash proceeds, a loss on sale due to an excess of the asset's net book value over proceeds, or liabilities which must be settled in the future at amounts that are higher than we anticipated. In addition, although we may successfully divest oil and gas assets, we may retain certain related contracts. For example, although we sold our Marcellus Shale upstream properties in 2017, we retained significant obligations under firm transportation contracts. Our inability to fully commercialize these contracts and reduce the associated financial commitments could result in a decrease in cash flows from operations. In addition, we may be required to recognize losses in accordance with exit or disposal activities. See Item 7. Management's Discussion of Financial Condition and Results of Operations – Liquidity and Capital Resources – Contractual Obligations.
We are exposed to counterparty credit risk as a result of our receivables, hedging transactions and cash investments.
We are exposed to risk of financial loss from joint venture and other receivables. We are the operator on a majority of our joint venture development projects, including Leviathan. As joint venture operator, we pay joint venture expenses and make cash calls on nonoperating partners for their respective shares of joint venture costs. These projects are capital intensive and, in some cases, a nonoperating partner may experience a delay in obtaining financing for its share of the joint venture costs or have liquidity problems resulting in slow payment of joint venture costs that can result in potential delays in our development projects. In addition, some of our joint venture partners are not as creditworthy as we are and may experience credit rating downgrades or liquidity problems that may hinder their ability to obtain financing. Counterparty liquidity problems could result in a delay in receiving proceeds from reimbursement of joint venture costs. Nonperformance by a joint venture partner could result in significant financial losses.
We have cash and cash equivalents deposited with financial institutions, a majority of which is invested in money market funds and short-term deposits with major financial institutions. In addition, our hedging activities may expose us to counterparty credit risk or, in some cases, cause us to incur significant cash settlements. As an entity entering into derivatives transactions under master agreements that are subject to US laws, we are subject to some limitations on our ability to exercise default rights with respect to derivatives transactions with a financially-troubled bank. On January 1, 2019, the US Bank Regulators imposed additional restrictions on counterparties that are parties to certain types of Qualified Financial Contracts (QFCs) with major banks that have been designated as Global Systemically Important Banks (G-SIBs). These QFCs include various master agreements and the financial derivatives transactions that are entered into under such master agreements with G-SIBs as counterparties.
While we monitor the creditworthiness of joint venture partners, purchasers, banks and financial institutions with which we conduct business, we are unable to predict sudden changes in solvency of these counterparties and may be exposed to associated risks. Credit enhancements have been obtained from some parties in the form of parental guarantees, letters of credit or credit insurance; however, not all of our counterparty credit is protected through guarantees or credit support. In addition, we maintain credit insurance associated with specific purchasers. However, nonperformance by a hedge counterparty or financial institution could result in significant financial losses.
Commodity hedging transactions may limit our potential gains or fail to protect us from declines in commodity prices.
In order to reduce the impact of commodity price uncertainty and increase cash flow predictability relating to the marketing of our crude oil and natural gas, we enter into hedging arrangements with respect to a portion of our expected revenues. Our hedges, consisting of a series of derivative instrument contracts, are limited in duration, usually for periods of one to three years. While intended to reduce the effects of volatile crude oil and natural gas prices, such transactions may limit our potential gains if prices rise over the price established by the arrangements. Conversely, our hedging program may be inadequate to protect us from continuing and prolonged declines in the price of crude oil or natural gas. See Item 8. Financial Statements and Supplementary Data – Note 13. Derivative Instruments and Hedging Activities.
The insurance we carry is insufficient to cover all of the risks we face, which could result in significant financial exposure.

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Exploration for and production of crude oil and natural gas can be hazardous, involving natural disasters or other catastrophic events such as hurricanes, earthquakes, blowouts, well cratering, fire and explosion, loss of well control, pipeline disruptions, mishandling of fluids and chemicals, and possible underground migration of hydrocarbons and chemicals, any of which can result in damage to or destruction of wells or formations or production facilities, injury to persons, loss of life, or damage to property and the environment. Exploration and production activities are also subject to risk from other disruptive events such as terrorist acts, piracy, civil disturbances, war, and expropriation or nationalization of assets, or other interruptions, such as cyber security breaches, which can cause loss of or damage to our property.
Our insurance program and memberships in domestic and international dedicated oil spill and emergency response organizations may not minimize or fully protect us from losses resulting from damages to or the loss of physical assets or loss of human life, liability claims of third parties, and business interruption (loss of production) attributed to certain assets and including such occurrences as well blowouts and resulting oil spills. We do not have insurance protection against all the risks we face, because we choose not to insure certain risks, insurance is not available at a level that balances the cost of insurance and our desired rates of return, or actual losses may exceed coverage limits.
We expect the future availability and cost of insurance to be impacted by events such as hurricanes, earthquakes and other natural disasters. Impacts could include tighter underwriting standards, limitations on scope and amount of coverage, and higher premiums, and will depend, in part, on future changes in laws and regulations regarding exploration and production activities in areas in which we operate, including possible increases in liability caps for claims of damages from oil spills. We will continue to monitor for any legislative or regulatory changes related to exploration and production and its potential impact on the insurance market and our overall risk profile, and adjust our risk and insurance program to provide protection, at a level that we can afford considering the cost of insurance and our desired rates of return, against disruption to our operations and cash flows.
If an event, for example, a major offshore incident resulting in significant personal injury and/or environmental and physical damage, occurs that is not covered by insurance or not fully protected by insured limits, it could have a significant adverse impact on our financial condition, results of operations and cash flows. See Items 1. and 2. Business and Properties – Risk and Insurance Program.
Item1B.  Unresolved Staff Comments
None.
Item 3.  Legal Proceedings
We are involved in various legal proceedings in the ordinary course of business. These proceedings are subject to the uncertainties inherent in any litigation. We are defending ourselves vigorously in all such matters and we believe that the ultimate disposition of such proceedings will not have a material adverse effect on our financial position, results of operations or cash flows. See Item 8. Financial Statements and Supplementary Data – Note 11. Commitments and Contingencies.
Item 4.  Mine Safety Disclosures
Not Applicable.

PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
Common Stock   Our common stock, $0.01 par value, is listed and traded on the NYSE under the symbol “NBL.” The declaration and payment of dividends are determined on a quarterly basis and are at the discretion of our Board of Directors and the amount thereof will depend on our results of operations, financial condition, contractual restrictions, cash requirements, future prospects and other factors deemed relevant by the Board of Directors.
Dividends On January 29, 2019, our Board of Directors declared a quarterly cash dividend of $0.11 per common share. The dividend will be paid February 25, 2019, to shareholders of record on February 11, 2019. See Item 8. Financial Statements and Supplementary Data – Consolidated Statements of Shareholders' Equity.
Transfer Agent and Registrar   The transfer agent and registrar for our common stock is Computershare Trust Company N.A., 250 Royall Street, Canton, MA, 02021.
Shareholders’ Profile   Pursuant to the records of the transfer agent, as of February 7, 2019, the number of holders of record of our common stock was 541.

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Stock Repurchases   The following table summarizes repurchases of our common stock occurring in fourth quarter 2018:
Period
 
Total Number of
Shares Purchased (1)
 
Average
Price Paid
Per Share
 
Total Number of
Shares Purchased
as Part of Publicly
Announced Plans or
Programs (2)
 
Approximate Dollar
Value of Shares that
May Yet Be
Purchased Under the
Plans or Programs
 
 
 
 
 
 
 
 
(millions)
10/1/2018 - 10/31/2018
 
59,006

 
$
29.37

 

 
 
11/1/2018 - 11/30/2018
 
1,630,968

 
24.57

 
1,621,076

 
 
12/1/2018 - 12/31/2018
 
964,927

 
23.53

 
964,609

 
 
Total
 
2,654,901

 
$
24.29

 
2,585,685

 
$
455

(1) Includes stock repurchases of 69,216 shares during the period related to stock received by us from employees for the payment of withholding taxes due on shares of common stock issued under stock-based compensation plans.
(2) During fourth quarter 2018, we repurchased and retired 2,585,685 shares of common stock at an average purchase price of $24.19 per share pursuant to the $750 million share repurchase program, authorized by the Board of Directors and announced in February 2018, which expires on December 31, 2020.
Stock Performance Graph   This graph shows our cumulative total shareholder return over the five-year period from December 31, 2013 to December 31, 2018. The graph also shows the cumulative total returns for the same five-year period of the S&P 500 Index and a peer group of companies. The cumulative total return of the common stock of our peer group of companies includes the cumulative total return of our common stock.
Our peer group includes a broad group of US onshore and global exploration and production companies which are further diversified by location and number of resource plays as well as level of integration within the crude oil and natural gas business cycle. Our peer group consists of the following:
Anadarko Petroleum Corp.
Devon Energy Corp.
Noble Energy, Inc.
Apache Corp.
EOG Resources, Inc.
Pioneer Natural Resources Co.
Cabot Oil & Gas Corp.
Hess Corp.
Range Resources Corp.
Chesapeake Energy Corp.
Marathon Oil Corp.
Southwestern Energy Co.
Continental Resources, Inc.
Murphy Oil Corp.
 
The comparison assumes $100 was invested on December 31, 2013 in our common stock, in the S&P 500 Index and in our peer group of companies and assumes that all of the dividends were reinvested. In addition, the peer group investment is weighted based upon the market capitalization of each individual company within the peer group.

41


A5YRSCUMULATIVETOTALRETURN.JPG
Year Ended December 31,
2014
2015
2016
2017
2018
Noble Energy, Inc.
$
70.38

$
49.73

$
58.15

$
45.11

$
29.47

S&P 500
113.69

115.26

129.05

157.22

150.33

Peer Group
86.06

53.24

76.93

68.75

51.93



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Item 6. Selected Financial Data
 
 
Year Ended December 31,
(millions, except as noted)
 
2018
 
2017
 
2016
 
2015
 
2014
Revenues and Income
 
 
 
 
 
 
 
 
 
 
Total Revenues