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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2019
or
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 
For the transition period from          to          

Commission file number: 001-07964

http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=13363660&doc=28
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
 
Trading Symbol(s)
 
Name of each exchange on which registered
Common Stock, $0.01 par value
 
NBL
 
The Nasdaq Stock Market LLC
 
 
 
 
(NASDAQ Global Select Market)
Securities registered pursuant to Section 12(g) of the Act: None 
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes No 
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes No 
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes No 
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes No 
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer

Accelerated filer
Non-accelerated filer
Smaller reporting company
Emerging growth company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
 Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes No
Aggregate market value of Common Stock held by nonaffiliates as of June 30, 2019: $10.7 billion.
Number of shares of Common Stock outstanding as of December 31, 2019: 478,509,368.

DOCUMENTS INCORPORATED BY REFERENCE
Portions of the Registrant’s definitive proxy statement for the 2020 Annual Meeting of Shareholders to be held on April 28, 2020, which will be filed with the Securities and Exchange Commission within 120 days after December 31, 2019, are incorporated by reference into Part III.




TABLE OF CONTENTS

PART I
Items 1. and 2.
Item 1A.
Item 1B.
Item 3.
Item 4.
PART II
Item 5.
Item 6.
Item 7.
Item 7A.
Item 8.
Item 9.
Item 9A.
Item 9B.
PART III
Item 10.
Item 11.
Item 12.
Item 13.
Item 14.
PART IV
Item 15.
Item 16.





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, including our capital spending plans;
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 (Nasdaq: NBL) is an independent crude 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 our values, 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 through an Integrated Development Plan (IDP) approach, which is designed to optimize capital efficiency and drive returns. In the global offshore, our notable exploration and major project successes have led to sanction (meaning final investment decision has been reached) of multiple major development projects and have provided long-lived cash flows to our business. In addition, our midstream business and equity method investments represent essential components of our business as well as necessary and integral elements of our value chain.
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, exploration, development, and production (Oil and Gas Exploration and Production). The Midstream reportable segment consists primarily of our interest in Noble Midstream Partners LP (Noble Midstream Partners, Nasdaq: NBLX), which we consolidate. Noble Midstream Partners develops, owns, and operates domestic midstream infrastructure assets, as well as invests in other

2


midstream projects, with current focus on the DJ and Delaware Basins. See Item 8. Financial Statements and Supplementary Data – Note 3. Segment Information.
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 and established basin 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 US onshore production.
The map below illustrates the locations of our significant exploration and production activities:
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Development Activities Our development projects have resulted from exploration success, leasing activities, and periodic strategic acquisitions. We believe 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 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 deploy 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 the Leviathan natural gas field, offshore Israel, which commenced production at the end of December 2019, as well as the Alen Gas Monetization project in West Africa.
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 2019, we conducted limited exploration activities as we focused our capital investment program on the development of US onshore assets and progressing the Leviathan development project to first production in December 2019.

3


Asset Impairment  During fourth quarter 2019, we recorded impairment expense related to our proved properties in the Eagle Ford Shale. See Item 8. Financial Statements and Supplementary Data – Note 10. Impairments.
Proved Reserves Disclosures
Proved Oil and Gas Reserves   Proved reserves at December 31, 2019 were as follows:
 
 
Crude Oil & Condensate
 
NGLs
 
Natural Gas
 
Total
 
 
(MMBbls)
 
(MMBbls)
 
(Bcf)
 
(MMBoe)(1)
 
(Percent)
Proved Developed
 
 
 
 
 
 
 
 
 
 
United States
 
176

 
138

 
1,055

 
490

 
33
%
Israel
 
9

 

 
5,463

 
920

 
61
%
Equatorial Guinea
 
25

 
10

 
355

 
94

 
6
%
Total Proved Developed Reserves
 
210

 
148

 
6,873

 
1,504

 
100
%
Proved Undeveloped
 
 

 
 
 
 

 
 

 
 
United States
 
201

 
125

 
964

 
486

 
89
%
Israel
 

 

 
132

 
22

 
4
%
Equatorial Guinea
 
2

 
5

 
182

 
38

 
7
%
Total Proved Undeveloped Reserves
 
203

 
130

 
1,278

 
546

 
100
%
Total Proved Reserves
 
413

 
278

 
8,151

 
2,050

 
 
(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 are 48% US onshore and 52% international. The commodity mix is 34% liquids (crude oil and NGLs), 50% international natural gas and 16% US natural gas. Changes in proved reserves were as follows:
 
 
Year Ended December 31,
(MMBoe)
 
2019

2018

2017
Proved Reserves, Beginning of Year
 
1,929

 
1,965

 
1,437

Revisions of Previous Estimates(1)
 
(50
)
 
(2
)
 
135

Extensions, Discoveries and Other Additions
 
305

 
223

 
736

Purchase of Minerals in Place
 

 

 
57

Sale of Minerals in Place
 
(2
)
 
(128
)
 
(261
)
Production
 
(132
)
 
(129
)
 
(139
)
Proved Reserves, End of Year
 
2,050

 
1,929

 
1,965

(1) 
Includes negative price revisions of 53 MMBoe in 2019 and positive price revisions of 27 MMBoe and 30 MMBoe in 2018 and 2017, respectively.
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)   Changes in PUDs, which total 27% of proved reserves, were as follows for the year ended December 31, 2019:
(MMBoe)
 
United States
 
Israel (1)
 
Equatorial Guinea
 
Total
Proved Undeveloped Reserves, Beginning of Year
 
560

 
612

 
3

 
1,175

Revisions of Previous Estimates
 
(67
)
 
(39
)
 
4

 
(102
)
Extensions, Discoveries and Other Additions
 
167

 

 
34

 
201

Conversion to Proved Developed
 
(174
)
 
(551
)
 
(3
)
 
(728
)
Proved Undeveloped Reserves, End of Year
 
486

 
22

 
38

 
546

 
 
 
 
 
 
 
 
 
Conversion Percentage (Percent of Beginning Balance)
 
31
%
 
90
%
 
100
%
 
61
%
(1) 
In Israel, PUDs revisions of previous estimates reflects a reclassification to developed reserves associated with our Tamar field based upon our determination the reserves are accessible with limited further development. As such, we concurrently reflect an upward

4


revision within proved developed reserves. Conversions to proved developed reserves relate to commencement of Leviathan production in December 2019.
Revisions of Previous PUD Estimates Revisions of previous PUD estimates were as follows for the year ended December 31, 2019:
(MMBoe)
 
DJ Basin
 
Delaware Basin
 
Israel
 
Equatorial Guinea
 
Total
Price
 
(2
)
 
(15
)
 

 
3

 
(14
)
Development Plans
 
(19
)
 
(25
)
 
(39
)
 
1

 
(82
)
Performance
 

 
(6
)
 

 

 
(6
)
Total
 
(21
)
 
(46
)
 
(39
)
 
4

 
(102
)
Extensions, Discoveries and Other Additions PUD additions in US onshore are primarily located in the DJ Basin, resulting from the inclusion of new wells within drilling plans. Equatorial Guinea additions relate to the April 2019 sanction of the Alen Gas Monetization project, for which first sales are expected in the first half of 2021.
Conversion to Proved Developed Our development plans will result in the conversion of all PUDs to developed reserves within five years of their initial recognition, with the exception of Tamar Southwest PUDs, offshore Israel. Tamar Southwest PUDs are approximately 4% of total PUDs and have remained undeveloped since initial disclosure in 2013. In 2019, we received final approval of the development plan from the government of Israel and progressed capital investment in the field, including laying subsea equipment for future tie-in of field production into existing Tamar infrastructure. Our development plan includes additional capital investment in 2020 and conversion of Tamar Southwest PUDs to proved developed reserves in 2023, which we currently believe will align start-up with local and regional natural gas demand.
PUDs are expected to be recovered from new wells on undrilled acreage or from existing wells where additional capital expenditures are required, such as from drilled but uncompleted (DUC) wells. As of December 31, 2019, less than 10% of our PUDs were associated with US onshore DUC well locations. Our development plan contemplates production to commence from these wells in 2020.
When preparing development plans and estimates of PUDs, we consider the future economic development of reserves based on our estimates of future pricing, future investments, production and other economic factors that are excluded from the Securities and Exchange Commission (SEC) reserves requirements that specify inputs be based upon current existing conditions. For example, in periods of fluctuating commodity prices, improving prices may yield economic PUDs but the Company's planned future capital outlay may not support the development of all economic PUDs. As such, certain economic PUDs may not be recorded as we record PUDs in connection with our future development plans to ensure conversion of PUDs within five years of their initial recognition. See Item 8. Financial Statements and Supplementary Data – Supplemental Oil and Gas Information (Unaudited).
Development Costs  Costs incurred to develop our PUDs in 2019 totaled $1.5 billion. Of this amount, $1.1 billion, $399 million and $48 million related to the conversion of year end 2018 PUDs to proved developed reserves in US onshore, the Leviathan field offshore Israel and the Aseng crude oil well in Equatorial Guinea, respectively.
In addition, we spent $131 million to convert unproved reserves to proved developed reserves in US onshore and $24 million progressing PUDs that have not yet been converted to proved developed reserves.
Future Development Costs Future development costs include amounts we expect to spend converting PUDs to proved developed reserves. Estimated future development costs for PUDs as of December 31, 2019, are as follows:
 
 
Year Ended December 31,
(millions)
 
2020
 
2021
 
2022
Future Development Costs
 
$
1,191

 
$
920

 
$
994

Estimated future development costs include capital spending on development projects. PUDs related to these projects will be reclassified to proved developed reserves when production commences.
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;

5


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, exploration 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 39 years of industry experience. Since 2006, 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 2019, 2018, and 2017, our Audit Committee retained NSAI to perform audits of proved reserves. The reserves audit for 2019 included a detailed review of seven of our major US onshore and international fields, which covered approximately 99% of total proved reserves.
In connection with the 2019 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, 2019, 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.

6


Sales Volumes, Price and Cost Data   The table below includes sales volumes, price and cost data for each geographical area and field that contained 15% or more of total proved reserves as of December 31, 2019. Total proved reserves for the Leviathan field accounted for over 15% of total proved reserves as of December 31, 2019. While the Leviathan field commenced production in December 2019, natural gas sales from that field in 2019 were immaterial; thus, the Leviathan field is not presented in the table below.

 
 
Sales Volumes
 
Average Sales Price (1)
 
Average Production Cost (2)
 
 
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, 2019
 
 
 
 
 
 
 
 
 
 
 
 
United States
 
 
 
 

 
 
 
 
 
 
 
 
 
 
DJ Basin
 
25,494

 
11,931

 
109,790

 
$
56.33

 
$
12.96

 
$
1.70

 
$
3.55

Other US
 
18,278

 
12,832

 
78,408

 
54.78

 
15.58

 
2.02

 
6.37

Total US
 
43,772

 
24,763

 
188,198

 
$
55.68

 
$
14.32

 
$
1.83

 
$
4.80

Israel
 
106

 

 
81,269

 
$
56.07

 
$

 
$
5.55

 
$
2.73

Equatorial Guinea
 
4,792

 

 
67,729

 
61.03

 

 
0.27

 
4.73

Total Consolidated Operations
 
48,670

 
24,763

 
337,196

 
$
56.21

 
$
14.32

 
$
2.41

 
$
4.63

Equity Investment (3)
 
535

 
1,634

 

 
58.65

 
31.77

 

 

Total
 
49,205

 
26,397

 
337,196

 
$
56.24

 
$
15.40

 
$
2.41

 

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
 
113

 

 
86,461

 
$
63.25

 
$

 
$
5.47

 
$
2.30

Equatorial Guinea
 
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 Investment (3)
 
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
 
6,460

 

 
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 Investment (3)
 
662

 
2,162

 

 
55.13

 
38.48

 

 

Total
 
47,806

 
23,248

 
407,976

 
$
49.84

 
$
24.81

 
$
3.01

 

(1) 
Average sales prices exclude gains or losses on commodity derivative instruments. See Item 8. Financial Statements and Supplementary Data – Note 14. Derivative Instruments and Hedging Activities.
(2) 
Average production cost includes oil and gas production operating costs, workover and repair expense and excludes production and ad valorem taxes, gathering, transportation and processing expense, and other royalty expense.
(3) 
Volumes represent sales of condensate and liquefied petroleum gas (LPG) from the LPG plant in Equatorial Guinea.
(4) 
Amounts include Gulf of Mexico assets prior to sale in second quarter 2018 and Marcellus Shale assets prior to sale in second quarter 2017. See Item 8. Financial Statements and Supplementary Data – Note 4. Acquisitions and Divestitures.

7


At December 31, 2019, our operated properties accounted for substantially all of our total sales volumes. 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, 2019 were as follows:
 
Crude Oil Wells
 
Natural Gas Wells
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States
4,819

 
4,231

 
807

 
764

 
5,626

 
4,995

Israel

 

 
10

 
3

 
10

 
3

Equatorial Guinea
6

 
2

 
23

 
8

 
29

 
10

Total
4,825

 
4,233

 
840

 
775

 
5,665

 
5,008

 
Developed and Undeveloped Acreage   Developed and undeveloped acreage (including both leases and concessions) in which we held an interest at December 31, 2019 were as follows: 
 
Developed Acreage
 
Undeveloped Acreage
(thousands of acres)
Gross
 
Net
 
Gross
 
Net
United States
575

 
453

 
495

 
438

Israel
309

 
123

 
161

 
62

Equatorial Guinea 
284

 
118

 
26

 
10

Newfoundland, Canada

 

 
2,331

 
681

Colombia

 

 
2,174

 
869

Gabon

 

 
671

 
403

Cyprus

 

 
95

 
33

Cameroon

 

 
168

 
168

Total
1,168

 
694

 
6,121

 
2,664

The table above 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. As of December 31, 2019, acreage expiring in the next three years is as follows:
 
Net Undeveloped Acreage
(thousands of acres)
2020
 
2021
 
2022
United States (1)
29

 
59

 
28

Israel (2)
46

 

 

Gabon

 
403

 

Total
75

 
462

 
28

(1) 
Approximately 80% relates to acreage on which we have not recorded PUDs. Of the remaining acreage, there are no PUDs on acreage we plan to let expire as our development plan contemplates the drilling or renewing of leases associated with this acreage prior to expiration.
(2) 
Acreage relates to the Alon D license.

8


Drilling Activity   The results of crude oil and natural gas wells completed, regardless of when drilling was initiated, were as follows:
 
Net Exploratory Wells
 
Net Development Wells
 
Total
 
Productive
 
Dry
 
Total
 
Productive
 
Dry
 
Total
 
Year Ended December 31, 2019
 
 
 
 
 
 
 
 
 
 
 
 
 
United States

 

 

 
183.9

 

 
183.9

 
183.9

Israel

 

 

 
1.6

 

 
1.6

 
1.6

Equatorial Guinea

 

 

 
0.4

 

 
0.4

 
0.4

Total

 

 

 
185.9

 

 
185.9

 
185.9

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

In addition to the wells in the table above, wells that were in the process of drilling or completing at December 31, 2019 were as follows: 
 
Exploratory(1)
 
Development(1)
 
Total
 
Gross
 
Net
 
Gross
 
Net
 
Gross
 
Net
United States

 

 
72.0

 
64.0

 
72.0

 
64.0

Total

 

 
72.0

 
64.0

 
72.0

 
64.0

(1) 
Amounts include wells awaiting completion activities, with the exception of Tamar Southwest as it is not in the process of completing at December 31, 2019. Amounts exclude wells drilled and suspended awaiting a sanctioned development plan or being evaluated to assess the economic viability of the well.
See Item 8. Financial Statements and Supplementary Data – Note 6. Capitalized Exploratory Well Costs and Undeveloped Leasehold Costs for additional information on suspended exploratory wells.

9


Oil and Gas Exploration and Production – Properties and Activities
US Onshore
Our US onshore operations are located in proven hydrocarbon basins. These assets provide low geologic-risk drilling opportunities in liquids-rich areas. In addition, we evaluate and consider other US onshore new venture prospects to complement our portfolio. US onshore locations as of December 31, 2019 are shown on the map below:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=13363660&doc=25
US onshore operations accounted for 77% of 2019 total consolidated sales volumes and 48% of total proved reserves at December 31, 2019. Approximately 39% of the proved reserves in the US are crude oil and condensate, 34% are natural gas and 27% are NGLs.
Key information for our US onshore operating locations as of, and for the year ended, December 31, 2019, is as follows:
 
DJ Basin
 
Delaware Basin
 
Eagle Ford Shale
 
Total
Net Acreage (thousands) (1)
336

 
92

 
35

 
463

Proved Reserves (MMBoe)
666

 
204

 
106

 
976

Sales Volumes (MBoe/d)
153

 
66

 
55

 
274

Gross Wells Drilled (2)
106

 
66

 
16

 
188

Gross Wells Brought Online
120

 
64

 
25

 
209

Gross Non-Operated Wells Participated In
2

 
21

 

 
23

(1) 
Amounts include net developed and net undeveloped acres. Total excludes approximately 181,000 net acres in the Powder River and Green River Basins and approximately 239,000 net acres in other US onshore locations.
(2) 
The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated. Amount excludes two refracture wells in the Eagle Ford Shale.
DJ Basin Our operations in the DJ Basin represent the largest asset within our US onshore asset portfolio. In 2019, we conducted drilling and development activity in three of our IDP areas, including Wells Ranch, Mustang, and East Pony. Our IDP approach has provided an opportunity to efficiently and economically develop our resources through leveraging infrastructure.
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. We are currently using three drilling rigs and two hydraulic fracturing crews.

10


We currently have approximately 385 approved and remaining drilling permits, primarily in our Mustang Comprehensive Drilling Plan (CDP). The vast majority of these permits have six-year terms. In addition, in September 2019, we submitted a permitting application for our second large-scale CDP in the state of Colorado. The CDP spans approximately 38,000 net acres in Wells Ranch and allows for up to 250 additional drilling permits. The Wells Ranch CDP acreage is located in an area of higher crude oil production.
Delaware Basin (Permian Basin) In 2019, we continued execution of the Delaware Basin IDP with a focus on maximizing lateral length, pad drilling, single zone completions, and infrastructure development. We began realizing the benefits of row development, which contributed to reduced well costs and improved cycle times. Newly installed electrical substations have increased reliability of production and reduced costs. We are currently using two rigs and two hydraulic fracturing crews.
We continue to focus on securing our crude oil takeaway position in the basin. We utilize the Advantage Pipeline System (below), which is 50% owned by Noble Midstream Partners, for a portion of our crude oil takeaway. We also utilize the EPIC Y-Grade Pipeline (defined below), which began interim crude service in August 2019. The EPIC Crude Oil Pipeline (below), to which substantially all of our acreage position in Reeves County, Texas is dedicated, is scheduled to come online in the first half of 2020. Our crude service will shift to the EPIC Crude Oil Pipeline once it comes online, and the EPIC Y-Grade Pipeline will commence Y-grade service. Noble Midstream Partners has ownership interests in entities that own these pipelines. See Item 8. Financial Statements and Supplementary Data – Note 5. Equity Method Investments.
Eagle Ford Shale During 2019, we continued to apply IDP learnings and enhancements, including optimizing completion designs to increase investment efficiency. As we focused on completion activities, we progressed DUC wells to production and tested co-development of both the Upper and Lower Eagle Ford formation zones. In 2019, we began testing refracturing concepts in the South Gates Ranch area, which could provide opportunities to re-develop approximately 75 to 100 wells.
US Onshore Exploration Activity Our US onshore exploration position includes more than 250,000 net acres, with approximately 181,000 net acres in Wyoming in the Powder River and Green River Basins. We continue to progress activities to obtain required approvals and permits.
See Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations – Results of Operations – Liquidity and Capital Resources.
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 for more than a decade. Previous exploration successes in these areas have yielded a large inventory of discovered resources which, through major project development, have the potential to contribute to long-term production and cash flow growth in the future.
During 2019, we progressed Phase 1 development of the Leviathan field, which commenced production on December 31, 2019. In addition, we advanced our Eastern Mediterranean regional natural gas export opportunities by executing natural gas sales and purchase agreements (GSPAs) and transportation agreements for the Leviathan and Tamar fields and continued 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), Colombia and other foreign locations are conducted in accordance with concession agreements, permits or licenses.
Eastern Mediterranean (Israel and Cyprus)   The Eastern Mediterranean, where we have identified the existence of substantial natural gas resources, is one of our core operating areas. Natural gas sales volumes, primarily from the Tamar field, represented approximately 10% of total consolidated sales volumes during 2019. Our operated offshore Israel leasehold position includes six leases and one license. Offshore Cyprus, we operate under the terms of a PSC, with acreage adjacent to our offshore Israel acreage.
Key information for our Eastern Mediterranean operating area as of, and for the year ended, December 31, 2019, is as follows:
 
Total
Proved Reserves (MMBoe) (1)
942

Sales Volumes (MMcf/d)
223

Net Developed Acres (thousands)
123

Net Undeveloped Acres (thousands)
95

Gross Wells Drilled (2)
4

Gross Wells Brought Online
4


11


(1) 
Includes 639 MMBoe, 281 MMBoe, and 22 MMBoe related to the Leviathan, Tamar, and Tamar Southwest fields, respectively.
(2) 
The number of wells drilled refers to the number of wells completed, regardless of when drilling was initiated.
Eastern Mediterranean locations as of December 31, 2019 are shown on the map below:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=13363660&doc=24
Domestic and Regional Natural Gas Demand The quantity of discovered natural gas resources at the Tamar and Leviathan fields has positioned Israel to meet domestic needs for decades and become a significant natural gas exporter. From offshore Israel projects, we have reliably delivered over 3.0 Tcf, gross, of natural gas primarily to Israeli customers, including the Israel Electric Corporation (IEC), the largest supplier of electricity in Israel. In mid-2019, the Tamar field achieved a milestone, reaching 2.0 Tcf of cumulative gross production with over 99% runtime since startup.
Leviathan Development Project In order to expand Israel's supply of natural gas, create redundancy in infrastructure, and meet increasing regional demand, we progressed the initial phase of development at the Leviathan field, our largest discovery to date. We sanctioned the development in February 2017 and achieved first gas, ahead of schedule and under budget, with first production in December 2019.
The initial development includes four subsea wells, each capable of flowing more than 300 MMcf/d of natural gas. Production is gathered at the field and delivered via two 73-mile flowlines to a fixed platform, with full processing capabilities, located approximately 6 miles offshore. Processed gas connects to the Israel Natural Gas Lines Ltd. (INGL) onshore transportation grid at Dor, in the northern part of the country, and to regional markets via onshore and offshore export pipelines. The field began producing at the end of 2019 and will continue to ramp up to full production during 2020.
GSPAs and Regional Transportation Together, the Tamar and Leviathan developments have total installed production capacity of approximately 2.3 Bcfe/d and are supplying natural gas under multiple long-term GSPAs to regional customers in Israel, Jordan and Egypt. Sales of natural gas to the National Electric Power Company Ltd. of Jordan began in January 2020. The gas is transported via the INGL grid to customers in Jordan and Egypt via the Arab Gas Pipeline and EMG Pipeline (defined below) systems. Sales to Egyptian customers have also begun via the EMG Pipeline.
During 2019, we and our partners amended the previously agreed GSPAs with our Egyptian customers. The amended agreements provide for total combined firm contract quantities of 3.0 Tcf of natural gas, gross, more than doubling the firm volume commitments previously agreed. In addition, each agreement has been extended by five years to reflect 15-year terms. These contracts allow for natural gas sales up to 650 MMcf/d, gross, by mid-2022. Increased export flow via the EMG Pipeline

12


also depends on successful completion of certain de-bottlenecking projects which are under development. See Delivery Commitments.
In fourth quarter 2019, we acquired an effective, indirect interest of approximately 10%, net, in the entity that owns the EMG Pipeline (EMG Pipeline). We, along with parties to the transaction, including certain of our upstream partners, entered into an agreement to jointly operate the EMG Pipeline, securing access to the pipeline’s full capacity for a 10-year term, with extension terms available.
Regional Expansion Opportunities We expect our Eastern Mediterranean business to continue to grow in the future. In Israel, we expect continued coal conversion and increases in power, industrial, and transportation usage. In Jordan, we expect increasing industrialization leading to increased natural gas consumption. In Egypt, growth is anticipated in all market segments, with the country focused on becoming a regional natural gas hub. The Leviathan development plan allows for significant future cost-effective field capacity expansion from its initial capacity of approximately 1.2 Bcf/d to 2.1 Bcf/d. We are currently assessing future development and expansions alternatives. We are also assessing the possibility for a Tamar expansion project which could expand field deliverability from the current capacity level of approximately 1.1 Bcf/d up to approximately 2.0 Bcf/d, allowing for additional regional export. Expansion options could include additional investments in pipelines, wells, and platform upgrades. In January 2019, the Petroleum Commissioner of Israel approved the development plan for our Tamar Southwest discovery, which would access additional natural gas resources through a new well.
We also have significant discovered resources at the Aphrodite field, offshore Cyprus. In November 2019, we signed a PSC with the Government of Cyprus and were issued our exploitation license, which includes a development plan that would increase the delivery of natural gas to regional customers.
Timing of sanction for any expansion project is dependent upon gas sales and midstream agreements, as well as regulatory approvals from respective governments and internal company sanction decisions.
West Africa (Equatorial Guinea, Cameroon and Gabon)   West Africa includes the Alba field, Block O and Block I offshore Equatorial Guinea, the YoYo Block offshore Cameroon, and one block offshore Gabon. In West Africa, our interests may differ due to 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 investments, contributed an average of 44 MBoe/d of sales volumes in 2019, representing approximately 12% of total consolidated sales volumes. At December 31, 2019, Equatorial Guinea had proved reserves of 132 MMBoe, which represents approximately 6% of total proved reserves.
West Africa locations as of December 31, 2019 are shown on the map below:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=13363660&doc=23

13


Aseng Field Aseng, an oil field (40% operated working interest, 38% revenue interest) on Block I, includes six horizontal producing wells flowing to the Aseng floating production, storage and offloading vessel (FPSO) where the crude oil is stored until offloaded and sold. During 2019, sales volumes from the Aseng field averaged 5 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, 2019, has produced over 103 MMBbls of cumulative gross crude oil production.
In third quarter 2019, we drilled and completed the Aseng 6P development well, which is mitigating field decline. First production began in fourth quarter 2019.
Alen Field   Alen is a natural gas and condensate field (51% operated working interest, 45% revenue interest) primarily on Block O 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. Sales volumes averaged approximately 3 MBbl/d, net, during 2019. The Alen platform will 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 (33% non-operated working interest, 32% revenue interest). 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. The LPG processing plant and the methanol plant are located on Bioko Island, Equatorial Guinea. During 2019, Alba field sales volumes averaged 42 MBoe/d, net, reflecting 36 MBoe/d, net, attributable to total consolidated sales volumes and 6 MBoe/d, net, attributable to an equity investment.
We sell our share of primary condensate under short-term contracts at market-based prices. We sell our share of natural gas production to the LPG plant, the methanol plant, an unaffiliated liquefied natural gas (LNG) plant (EG LNG) and a power generation plant. The LPG plant is owned by Alba Plant LLC (Alba Plant), in which we have a 28% interest. Alba Plant sells its LPG products and secondary condensate at our marine terminal at prevailing market prices. 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. We account for our interests in 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 5. Equity Method Investments.
West Africa Natural Gas Monetization   We continue efforts to monetize our significant natural gas discoveries offshore West Africa. In second quarter 2019, we sanctioned the Alen natural gas development. Definitive agreements in support of the project were executed between the Alen field partners, the Alba Plant and EG LNG plant owners, as well as the government of the Republic of Equatorial Guinea.