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Index to Financial Statements

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

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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.



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Index to Financial Statements

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.



Table of Contents
Index to Financial Statements


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

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Index to Financial Statements

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

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The map below illustrates the locations of our significant crude oil and natural gas exploration and production activities:
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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.





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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


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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%.

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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.

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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.

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(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.

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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.

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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:
http://api.tenkwizard.com/cgi/image?quest=1&rid=23&ipage=12719181&doc=28
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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Index to Financial Statements

(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